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HomeMy WebLinkAboutCalista Region Energy Needs Study Part II Final Report Vol. 2 2002CALISTA REGION ENERGY NEEDS STUDY PART II NUVISTA LIGHT & POWER, INC. 301 Calista Court Anchorage, Alaska FINAL REPORT VOLUME 2 APPENDICIES July 1, 2002 Frank J. Bettine, P.E., Esq. 1120 E. Huffman Road, PMB 343 Anchorage, AK 99515 (907) 336-2335 , A.1. System Load Flow Study, prepared by Electric Power System, Inc. A.2. Prospecting For Low Resistance Electrical Grounds in Permafrost Regions A.3. Optical Phase Ground Wire Information B.1. Spread Sheet Data B.2. Bethel Alaska Cogeneration Project, prepared by Precision Energy Services, Inc. B.3. Bethel Utilities, Inc. -Selected Tariff Documents C.1. Spread Sheet Data C.2. Crooked Creek, Alaska Cogeneration Project, prepared by Precision Energy Services, Inc. C.3. Budget Cost Estimates, Power Plant Fuel Tank Farms at Bethel, Crooked Creek and ine Site A.1. System Load Flow Study, prepared by Electric Power System, Inc. A DY, Srlectric 1 Systems Cc fe hy Qy Consulting Engineers SYSTEMS DONLIN MINE PROJECT FEASIBILITY STUDY May 29, 2002 Dr. James W. Cote, Jr., PE. David W. Burlingame, P.E. PHONE (907) 522-1953 * 3305 ARCTC BLVD., SUITE 201, ANCHORAGE, ALASKA 99503-4575 » FAX (907) 522-1182 * WWW.EPSINC.COM DONLIN MINE PROJECT — FEASIBILITY STUDY TABLE OF CONTENTS 1 2 System Configurations............csssssssssssssssssssssssesseseseessnsssssscssessssssnsnsssnsesesessnssssessnsnensnessesnensacaes 3 4 4.1 Case 1:40 KV SWGR Line, No Mine, 6 MW Wind Turbines ...0...........sescsssecsssseessseeccsseessssesesseeesnnes 5 42 Case 2 : 40 KV SWGR Line, Mine and 138 kV Line, 30 MW Wind Turbines 00.00... eeeeeseceeeeeeee 6 43 Case3:80kV SWGR Line, No Mine, 6 MW Wind Turbines... ecesecessessestesessesneseesnesteneened 6 44 Case4:80kV SWGR Line, Mine and 138 kV Line, 30 MW Wind Turbines 45 Case5:80kV SWGR Line, No Mine, 18 MW Wind Turbines 46 Case6:80kVSWGR Line, Mine and 138 kV Line, 18 MW Wind Turbines Conclusions Appendix A Appendix B-1 : Cases 1&2 - East and South Feeders, 40 kV SWGR.........sssssssssesssseeseesees 11 Appendix B-2 : Case 3 - 80 kV SWGR, No mine, 6 MW Wind. o oN Oo Appendix B-3 : Case 3 - 80 kV SWGR, No mine, 8 MW Wind. 10 Appendix B-4 : Case 4 - 80 kV SWGR, Donlin Mine, 30 MW Wind (15 MW outpul.......... 26 11 Appendix B-5 : Case 5 - 80 kV SWGR, No Mine, 18 MW Wind............::s:sssssssssssssssseereneensenes 33 12 Appendix B-6 : Case 6 - 80 kV SWGR, Donlin Mine, 18 MW Wind DONLIN MINE PROJECT — FEASIBILITY STUDY Introduction The Donlin Mine Project as currently proposed includes the development of the Donlin mine on the Kuskokwim River, a 138 kV transmission line from the mine to Bethel, AK, and several single wire ground retum (SWGR) distribution lines serving a number of Alaskan villages throughout southwestem Alaska. The mine is located approximately 175 miles up river from Bethel. Electric Power Systems, Inc. (EPS) has performed a feasibility study of this project. This study included configurations with and without the mine development, with either 40 kV or 80 kV SWGR line systems, and 6 MW, 18 MW, or 30 MW of Wind Farm Generation. System Configurations EPS studied 6 basic system configurations. These are : SWGR Line 5 Case Voltage Mine Wind Farm Generation 1 40 kV None 6 MW (3-2 MW plants) eee 2 40 kV 60 MW mine with 138 kV line | 30 MW (3-10 MW plants) 3 80 kV None 6 MW (3 - 2 MW plants) 4 80 kV 60 MW mine with 138 kV line | 30 MW (3-10 MW plants) 5 80 kV None 18 MW (3-6 MW Plants) 6 80 kV 60 MW mine with 138 kV line 18 MW (3-6 MW Plants) For each system, EPS performed distribution load flows to check substation voltage drop and conductor loading. EPS then modified the basic system models by adding switched capacitors at various points in the system to improve the voltage profile. System Models ESP performed the distribution load flows using DPA/G, a distribution analysis program from Stoner Associates, Inc. The modeling of each system component is discussed below. 3.1 Line Models The 138 kV line sections were modeled as 795 ACSR “Drake” conductor, with standard tower configuration. The model consists of one, three phase 138 kV line from Bethel to Donlin Mine, with several intermediate tap locations along the way. Several single phase loads are tapped off the line, plus a SWGR line is tapped off the 138 kV line, from the Kuskokwim River to the Bering Sea. The SWGR lines are modeled as Coming Starway OPGW D220-124/25 012E9 conductor, with the earth ground used as the retum path for all current. Impedances for this conductor were given (R, Xr, and Xc). These values were assumed to be for the conductor itself, without consideration of spacing and retum path, as is typical for overhead conductor data found in the standard conductor tables. EPS added the effects of the ground return as follows. DONLIN MINE PROJECT — FEASIBILITY STUDY The traditional model for ground return effects is based on Carson’s model. The ground return path is modeled as one of more image conductors located below the ground. The distance from each actual conductor to its image is given by the Carson model as Dy: = 658.5.) p/ f (meters) where p is the ground resistivity in ohm-meters (100 Q m, here), and f is frequency (60 Hz). The GMR of the image conductor is modeled as equal to the GMR of the actual conductor, and the resistance of the ground conductor is given by R,, = 9.869 *107 f (ohms / meter) where f is frequency (60 Hz). The inductive reactance spacing factor, Xd, for this configuration is given by X, =oF (Dy) 2x where w = 2nf, and » = 4 1°10” Him. The total resistance and reactance for the circuit, per unit length, must be a loop impedance to account for the voltage drop both in the actual conductor and in the ground retum path. The total loop inductive reactance is given by X sop =2(X, +X,) and the total loop resistance is given by R ‘loop =R+R, For the Coming Starway conductor, the following data was provided. R =0.466Q/ mile X, =1.5672/ mile X, =0.212*10° Q/ mile With ground retum effects included, the line series impedance and shunt reactance are given by R=0.561Q/mile X, =5.059Q/ mile B, =1.525*10~ mhos/ mile Load Models Load data for each village and for the mine project were provided from the Electric Load Forecast of 2000 PCE data. Based on these loads, the maximum village load studied was modeled as 125% of the 2020 estimated KW demand. The minimum village load was modeled as 50% of the 2010 KW demand. The load power factor was assumed to be 0.85 lagging for all village loads. Tables of the loads are included in Appendix A. The mine load was estimated at 60 MW maximum, and 40 MW minimum, with a power factor of 0.95 lagging. The mine load is the only three phase load in this system. The loads were modeled as constant impedance loads, such that the demand decreases with the square of the applied voltage. This is a typical model for this type of distribution load. DONLIN MINE PROJECT — FEASIBILITY STUDY 3.3 Transformer Models Transformers are included at the Bethel substation for connecting the Bethel generation to the main substation bus. The generation was modeled at 13.8 kV, and the main substation bus was modeled as either 69 kV or 138 kV, three phase, depending on the SWGR line voltage and presence of the mine and 138 kV line. Line to ground voltage on a 69 kV line-line system is 39.83 kV, labeled 40 kV for this study. Line to ground voltage on a 138 kV line-line system is 79.7 kV, labeled 80 kV for this study. Each transformer is modeled with 6% reactance and a X/R ratio of 10, or resistance of 0.6%, all on the transformer base. Generation transformers at Bethel were modeled as delta connected on the generation side, grounded wye connected on the high side. For the configurations that include the mine and 138 kV line, the Bethel substation was modeled as 138 kV, and each SWGR line is tapped off one phase directly when served at 80 kV, or served through a single phase, 80kV / 40 kV transformer when served at 40 kV. These primary feeder transformers were also assumed to be 6% reactance, and 0.6% resistance on their own base. Transformer tums ratios were always assumed to be at tap position 1.0, to provide conservative results. Normal operation would consider moving tap positions for improved voltage regulation. Additionally, no line drop compensation or voltage regulators were included in the model. 3.4 Generator Models Generation is included at Bethel, as a combination of coal-fired, combustion turbine, and diesel units. Generation is also included at three wind turbine farms, located along the coast. These wind turbines range from 2 MW to 10 MW in size. Three wind turbine sizes were studied. These include 6 MW total (3 — 2 MW units), 18 MW total (3 — 6 MW units), and 30 MW total (3 - 10 MW units). The wind turbines are modeled in DPA/G as constant PQ injections with a power factor of 1.0. The Bethel generation is not explicitly included in the DPA/G model. The DPA/G model holds the main substation bus (either 69 kV or 138 kV) at constant voltage. The model assumes that the generation along with load tap changers (LTCs) can regulate the high side bus voltage. These studies all assume a 1.0 per unit high side voltage. Actual operation could typical maintain a higher substation voltage through regulation by the Bethel generation or through the use of LTCs or voltage regulators. 3.5 Capacitor Models Fixed capacitors and automatically switched capacitors are included in the model for voltage control. Single phase capacitors are used on the SWGR lines, and three phase capacitors are used on the 138 kV line. 4 Study Results DPAVG results of the 6 cases are discussed below. Case labels for each case were previously included in the table in section 2. 4.1 Case 1:40 kV SWGR Line, No Mine, 6 MW Wind Turbines This system configuration contains a 69 kV main substation bus at Bethel. Each SWGR line was served by a single phase tap off of the 69 kV main bus at Bethel. Three 2 MW wind turbine farms are included along the coast. Five feeders are served from Bethel. DONLIN MINE PROJECT — FEASIBILITY STUDY These are labeled East, South, Southwest, West, and North. The loads at each village, the feeder serving each load, and the phasing of each feeder is shown in Appendix A. Load was distributed among the 3 phases to balance each phase as close as possible. Voltage regulation was possible along only two of the five feeders. Acceptable voltages are 95% to 105% of nominal. The two feasible feeders are the East and South feeders. DPAJG results are shown in Appendix B-1 for these 2 feeders. The DPA/G voltage results are presented on a 120V base. At 120 V, 95% is 114V and 105% is 126V. The remaining feeders could not be solved by DPA/G due to long line lengths and heavy load, even with voltage regulation provided by switched capacitors. Switched capacitors were included at every load point, up to and occasionally exceeding the kVAR demand of each load. This system configuration will not work at this voltage level and load level. 42 Case 2:40 kV SWGR Line, Mine and 138 kV Line, 30 MW Wind Turbines This system configuration contains a 138 kV main substation bus at Bethel. Four of the SWGR lines are each served by a single phase tap off of the 138 kV main bus at Bethel, using single phase 80/40 kV transformers. Three 10 MW wind turbine farms are included along the coast. The North feeder used in case 1 was converted to a 138 kV line from Bethel to the Donlin Mine, plus a SWGR line tap at Kalskag. The tap uses a 80/40 kV single phase transformer. The feeders are labeled East, South, Southwest, West, and 138 Line. The loads at each village, the feeder serving each load, and the phasing of each feeder is shown in Appendix A. Load was re-distributed among the 3 phases to balance each phase as close as possible. The Mine load is a three phase load. Voltage regulation was possible along only two of the five feeders. The presence of the 138 kV line and additional wind turbine generation does not improve the voltage problems along the problem feeders. The two feasible feeders are the East and South feeders. Specific results for this case are the same as the previous case 1, along the East and South feeders. The remaining feeders could not be solved by DPA/G due to long line lengths and heavy load, even with voltage regulation provided by switched capacitors. Switched capacitors were included at every load point, up to and occasionally exceeding the kVAR demand of each load. Wind turbine generation was adjusted to determine if lower generation, especially along the West and Southwest feeders would provide a solution, but none was found. This system configuration will not work at this voltage level and load level. 4.3 Case 3:80 kV SWGR Line, No Mine, 6 MW Wind Turbines This system configuration contains a 138 kV main substation bus at Bethel. Each SWGR line was served by a direct single phase tap off of the 138 kV main bus at Bethel. Three 2 MW wind turbine farms are included along the coast. Five feeders are served from Bethel. These are labeled East, South, Southwest, West, and North. The loads at each village, the feeder serving each load, and the phasing of each feeder is shown in Appendix A. Load was distributed among the 3 phases to balance each phase as close as possible. Voltage regulation was possible along four of the five feeders. The fifth feeder, North, is close to acceptable, with a voltage of 110.3V on a 120V base at the far end of the feeder, Kotlik. With an increased voltage at the main Bethel substation, this configuration could be made to work. DPA/G results are shown in Appendix B-2. DONLIN MINE PROJECT — FEASIBILITY STUDY When the wind turbine generation along the North feeder is increased, the voltage problems are alleviated. Increasing the wind turbine output to 4 MW raises the Kotlik voltage to above 120V, with switched capacitors distributed throughout the system. These results are provided in Appendix B-3. 44 Case 4: 80 kV SWGR Line, Mine and 138 kV Line, 30 MW Wind Turbines This system configuration contains a 138 kV main substation bus at Bethel. Four of the SWGR lines are each served by a direct single phase tap off of the 138 kV main bus at Bethel. Three 10 MW wind turbine farms are included along the coast. The North feeder used in case 3 was converted to a 138 kV line from Bethel to the Donlin Mine, plus a SWGR line tap at Kalskag. The feeders are labeled East, South, Southwest, West, and 138 Line. The loads at each village, the feeder serving each load, and the phasing of each feeder is shown in Appendix A. Load was re-distributed among the 3 phases to balance each phase as close as possible. The Mine load is a three phase load. Voltage regulation was possible for all feeders with sufficient shunt compensation added. The most difficult feeder to control is the 138 Line feeder and tapped SWGR line. The voltage at the mine could be brought within acceptable range by addition of shunt capacitors to bring the mine load to near 1.0 power factor, plus additional switched capacitors everywhere along the feeder. The wind turbine generation along the northem feeder, at Sheldon Point, had to be reduced to 6 MW to control voltage along the SWGR sections of the feeder. Improved voltage profile was obtained along the West feeder when the wind generation was adjusted to 5 MW, and along the Southwest feeder when generation was adjusted to 4 MW. Total wind generation was therefore 15 MW. DPA/G results are shown in Appendix B-4. DPA/G had a difficult time controlling voltage with switched capacitors along the northem feeder. The long length of the 138 kV line and the SWGR line tap makes voltage control difficult at the heavy load levels. Some consideration should be made of using other conductor types to decrease voltage drop. Additionally, fixed and switched capacitors were modeled at Donlin Mine, but a static var compensator (SVC) system should be considered at the mine to improve voltage regulation, especially during transients. This system configuration as proposed is very near the operating limit with respect to voltage drop. 4.5 Case 5:80 kV SWGR Line, No Mine, 18 MW Wind Turbines This system configuration is essentially the same as case 3, with the wind farm generation increased to 18 MW total. The case contains a 138 kV main substation bus at Bethel. Each SWGR line was served by a direct single phase tap off of the 138 kV main bus at Bethel. The Five feeders are labeled East, South, Southwest, West, and North. The loads at each village, the feeder serving each load, and the phasing of each feeder is shown in Appendix A. Load was distributed among the 3 phases to balance each phase as Close as possible. Voltage regulation was possible along all five feeders, with ample shunt compensation added along most feeders. When the wind turbine generation along the North feeder is increased, the voltage problems are alleviated. Increasing the wind turbine output to 6 MW raises the Kotlik voltage to near 119V, with switched capacitors distributed throughout the system. These results are provided in Appendix B-5. DONLIN MINE PROJECT — FEASIBILITY STUDY 4.6 Case 6: 80 kV SWGR Line, Mine and 138 kV Line, 18 MW Wind Turbines This system configuration is essentially the same as case 4, with the wind generation dispatched to 18 MW total. The system contains a 138 kV main substation bus at Bethel. Four of the SWGR lines are each served by a direct single phase tap off of the 138 kV main bus at Bethel. The feeders are labeled East, South, Southwest, West, and 138 Line. The loads at each village, the feeder serving each load, and the phasing of each feeder is shown in Appendix A. Load was re-distributed among the 3 phases to balance each phase as close as possible. The Mine load is a three phase load. Voltage regulation was possible for all feeders with sufficient shunt compensation added. The most difficult feeder to control is the 138 Line feeder and tapped SWGR line. The voltage at the mine could be brought within acceptable range by addition of shunt capacitors to bring the mine load to near 1.0 power factor, plus additional switched Capacitors everywhere along the feeder. The wind turbine generation along the northern, western, and southwestem feeders was dispatched to 6 MW each. DPA/G again had a difficult time controlling voltage with switched capacitors along the northem feeder. The long length of the 138 kV line and the SWGR line tap makes voltage control difficult at the heavy load levels. Some consideration should be made of using other conductor types to decrease voltage drop. Additionally, fixed and switched capacitors were modeled at Donlin Mine, but a static var compensator (SVC) system should be considered for the mine to improve voltage regulation, especially during transients. This system configuration as proposed is very near the operating limit with respect to voltage drop. 5 Conclusions Acceptable voltage regulation was possible only for the 80 kV SWGR line configurations. The 40 kV options all exhibit problems along the Southwest and West feeders. Additionally, the 40 kV option along the northern feeder was infeasible, with no power flow solution found. The 80 kV system without the mine is feasible, with increased wind turbine generation along the Yukon River system. The 18 MW wind turbine generation case provides a reasonable voltage profile. A significant amount of shunt compensation is necessary to regulate the feeder voltages. The 80 kV system including the mine is feasible with heavy application of switched capacitors. Voltage control at the mine is difficult but possible, and also requires shunt compensation (capacitors or SVC). The voltage performance of the 80 kV SWGR systems is very sensitive to changes in load and shunt compensation. Large amounts of fixed and switched capacitors are required to achieve an acceptable voltage profile. The use of one or more SVC systems to control voltage may be required for normal operation of this system. The use of long SWGR lines for distribution also creates some non-typical problems for voltage control. A significant amount of additional equipment in the form of capacitors and SVCs may be required. At the maximum loading conditions studied, 3 of the 5 feeders require wind turbine generation be on-line with an output between some maximum and some minimum. When the wind generation is changed, these feeders no longer exhibit acceptable voltage profiles. At reduced load levels, these feeders may also require shunt reactors for voltage control, due to the long length of these feeders. DONLIN MINE PROJECT - FEASIBILITY STUDY 6 Appendix A Without Donlin Mine : Village Village Village Village High P High Q LowP LowQ 620 384 184 531 329 163.5 455 282 139 295 183 78 556 345 171 1174 727 384 373 231 112 429 266 143.5 684 424 207.5 591 366 173 1093 677 362 250 155 76.5 730 452 231.5 1266 785 399.5 462 229 207 103 251 124.5 260 125.5 150 78.5 482 246.5 231 103.5 160 75.5 392 193.5 114 98 393 68.5 264 391.5 393 120 93.5 197.5 103 z 3 Village Owned Village Owned Village Owned Village Owned AVEC Villages Village Owned Russian Mission AVEC Villages Marshall AVEC Villages Pilot Station AVEC Villages St Mary’s/Pitka's Pc | AVEC Villages Mountain Village AVEC Villages Sheldon Point Village Owned Alakanuk AVEC Villages Emmonak AVEC Villages Kotlik Village Owned Napakiak Village Owned Tuntutuliak Village Owned Kongiganak Village Owned Kwigillingok Village Owned Kipnuk Village Owned Chefornak Village Owned Nightmute Village Owned Toksook Bay AVEC Villages Tununak AVEC Villages Atmautluak Village Owned Kasigluk/Nunapitch AVEC Villages Newtok Village Owned Chevak AVEC Villages Hooper Bay AVEC Villages Scammon Bay AVEC Villages Napaskiak Village Owned Eek AVEC Villages Quinhagak AVEC Villages Goodnews Bay AVEC Villages b a a a a a a a a a a a a a a c c c c c c c c c b b b b b b c c c c Total "4/3" DONLIN MINE PROJECT — FEASIBILITY STUDY With Donlin Mine : z $ Kwethluk Village Owned Russian Mission AVEC Villages Marshall AVEC Villages Pilot Station AVEC Villages St Mary's/Pitka's Point | AVEC Villages Mountain Village AVEC Villages Sheldon Point Village Owned AVEC Villages AVEC Villages Village Owned Village Owned Village Owned Village Owned Kwigillingok Village Owned Kipnuk Village Owned Village Owned Village Owned AVEC Villages AVEC Villages Village Owned AVEC Villages Village Owned AVEC Villages AVEC Villages AVEC Villages Village Owned AVEC Villages AVEC Villages AVEC Villages Village Owned Village Owned Village Owned AVEC Villages Village Owned Mine + J fan ead ad lind ad bind Ried bal find fel! Pl ban bl bau hiad id ili fic bi id bil fae nel eee intl fut dl fol ntl nl fal fa Total Total-Mine "473" DONLIN MINE PROJECT — FEASIBILITY STUDY 7 Appendix B-1 : Cases 1&2 - East and South Feeders, 40 kV SWGR FOI III IOI IO IOI ISITE ISI IOI TI IOI III Load-Flow Results For East FOI III III III IIIS IS III TIO IOI TO IIIT i te FO ek tee FOI I tote East Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg_ kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 69.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 603 364 18 86 120.0 B Feeder Feeder c 0 0 0 0 120.0 C Feeder Kwethluk Corning 11.0 69.0 0.0 B 601 372 18 3 603 364 18 86 1.8 1.8 118.2 2.0 -8.5 B Rwethluk FOI UIC IIIS TTI EOI I ttt ttetkeeKKH ~Load-Flow Results For South ********«* FOI IIIS III IIIS SITIES III ito South Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom %V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg _ kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 69.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 0 0 0 0 120.0 B Feeder Feeder Cc 1716 -108 43 -100 120.0 C Feeder Napaskiak Corning 6.0 69.0 0.0 Cc 411 55 10 12 1716 -108 43-100 0.4 0.4 119.6 6.2 41.9 C Napaskiak Capacitor (Wye-Gnd Connected) at Center of Section Napaskiak (Module 1 200 kvar/Ph) Phase C : Nominal = 200 kvar Actual = 200 kvar Eek Corning 46.0 69.0 0.0 C291, =21, 7 9 #1298 -204 33 -99 -0.3 0.0 120.0 23.8 117.7 Cc Eek Capacitor (Wye-Gnd Connected) at Center of Section Eek (Module 1 100 kvar/Ph) (Module 2. 100 kvar/Ph) Phase C : Nominal = 200 kvar Actual = 202 kvar Quinhagok Corning 86.0 69.0 0.0 c 638 -16 #15 7 983 -301 26 -96 -0.0 -0.0 120.0 13.9 28.9 C Quinhagok Capacitor (Wye-Gnd Connected) at Center of Section Quinhagok (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase C : Nominal = 400 kvar Actual = 411 kvar Goodnews Bay Corning 136.0 69.0 0.0 C 327 -216 9 3 331 -314 11 -73 -0.4 -0.4 120.4 3.4 -97.7 C Goodnews Ba Capacitor (Wye-Gnd Connected) at Center of Section Goodnews Bay (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase C : Nominal = 400 kvar Actual = 419 kvar ELECTRIC POWER SYSTEMS PAGE 11 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY 8 Appendix B-2 : Case 3 - 80 kV SWGR, No mine, 6 MW Wind DPA/G 5.1 is a Product of Stoner Associates (c)1998 Project : Donlin Mine Study - 80 kv Licensed To Electric Power Systems, Inc. Run Time 05/16/02 09:07:58 Application : Load-Flow Analysis Options, Messages, Warnings, and Errors: Analysis Options: Using By-Phase Model Convergence took 110 iterations with a convergence factor of 0.5000 Exceptions : H = Voltage > 126.0 L = Voltage < 114.0 Cc = Cond. Loading > 75% T = Tran. Loading > 95% FI III III III III III III III III ITI IOI III TIO TIO TIT A te tte ***eeeee4% Feeder and Substation Three-Phase Summary *********#* JOSS ISIIISI SISSIES SIGS IEICE TITIES I III IIIT III Ite KVA pf Amps Cust kW Loss Pct Loss Feeders of Bethel Substation East 677 91.1% 3 0 0 0.1% South 1695 -99.4% 1 0 12 0.7% West 2983 -100.0% 12 0 115 3.8% Southwest 1648 100.0% 7 0 27 1.6% North 6404 99.5% 27 0 333 5.2% TOTAL 13322 99.8% 0 486 3.7% FOI II III III III III IOI IOI IAI IIIT IOI IO IOI AOI TAA A te **xeeeee%% Peeder and Substation By-Phase Summary *****#*##e« FOI ISIC IIIT IOI III IIIT IIIT III ITI ITI TI ITT ITAA TIAA A =~ A/AB -- -- B/BC -- -- C/CA -- =<<= AMPS ic== CUSTOMERS KW LOSSES PCT kVA pf kVA pf kVA PF A B c A B c A B c Loss Feeders of Bethel Substation East 0 0.0% 677 91.1% 0 0.0% 0 8 0 0 0 0 0 0 0 0.1% South 0 0.0% 0 0.0% 1695 -99.4% 0 0 21 0 0 0 0 0 12 0.7% West 0 0.0% 2983 -100.0% 0 0.0% 0 37 0 0 0 0 0 115 0 3.8% Southwest 0 0.0% 0 0.0% 1648 100.0% 0 0 21 0 0 0 0 0 27 1.6% North 6404 99.5% 0 0.0% 0 0.0% 80 0 0 0 0 0 333 0 0 5.2% TOTAL 6404 99.5% 3607 99.8% 3335 -99.9% 0 0 0 333 115 38 3.7% ELECTRIC POWER SYSTEMS PAGE 12 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FI III III IIIT III IIT IIIS III III IIR IOI Ir **eeeteeee Feeder Mininimum / Maximum Summary ********** JOUUIGI ISIS II IOISIISII I SIIEIISIC III IOI IOI III Ie Maximum Section Drop Maximum Loss Pct Minimum Volts Max Conduct. Loading Section Max Section Max Section Min Section Max Feeders of Bethel Substation East A Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 A B Kwethluk 0.4 Kwethluk 100.0 Kwethluk 119.6 Kwethluk 2.4 B c Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 C South A Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 A B Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 B Cc Quinhagok 0.2 Eek 51.1 Napaskiak 120.0 Napaskiak 6.1 Cc West A Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 A B Newtok 1.9 Chevak 42.9 Hooper Bay 114.3 Chevak 11.4 B c Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 C Southwest A Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 A B Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 B Cc Kipnuk 1.3 Kipnuk 32.8 Tununak 115.7 Napakiak 5.9 C North A Kalskag 2.5 Kalskag 28.8 Kotlik 110.3 Akiachak 23.0 A B Akiachak 0.0 Akiachak 0.0 Akiachak 120.0 Akiachak 0.0 B c Akiachak 0.0 Akiachak 0.0 Akiachak 120.0 Akiachak 0.0 C ELECTRIC POWER SYSTEMS PAGE 13 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III IOI III III SII IITA A seeneaeeet® Load-Flow Results For East *******e9# FOS III III IIIT ESI ITI II III III ITT tee East Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 616 279 8 91 120.0 B Feeder Feeder c 0 0 0 0 120.0 C Feeder Kwethluk Corning 11.0138.0 0.0 B 616 381 9 2 616 279 8 91 0.4 0.4 119.6 0.5-101.8 B Kwethluk Capacitor (Wye-Gnd Connected) at Center of Section Kwethluk Phase B : Nominal = 0 kvar Actual = O kvar FOI III IOI III III IOI III IIIS III IO IOI OI IO AT eeeeeeEER ~Load-Flow Results For South *****#*#*#s# JOSS IOI ISI ISI III IIIT IEICE IIIT TTI ITE South Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 0 0 0 0 120.0 B Feeder Feeder c 1684 -189 21 -99 120.0 C Feeder Napaskiak Corning 6.0138.0 0.0 C 414 256 6 6 1684 -189 21 -99 0.0 0.0 120.0 1.5 -44.4 C Napaskiak Capacitor (Wye-Gnd Connected) at Center of Section Napaskiak Phase C : Nominal = 0 kvar Actual = 0 kvar Eek Corning 46.0138.0 0.0 C 293 182 4 5 1269 -401 17° «--95 -0.4 -0.3 120.3 5.9-337.0 Cc Eek Capacitor (Wye-Gnd Connected) at Center of Section Eek Phase C : Nominal = 0 kvar Actual = O kvar Quinhagok Corning 86.0138.0 0.0 C 640 396 9 4 970 -246 13-97 «0.2 -0.2 120.2 3.4-360.3 C Quinhagok Capacitor (Wye-Gnd Connected) at Center of Section Quinhagok Phase C : Nominal = 0 kvar Actual = O kvar Goodnews Bay Corning 136.0138.0 0.0 C 326 202 5 2 327-282 § -76 -0.0 -0.2 120.2 0.7-483.7 C Goodnews Ba Capacitor (Wye-Gnd Connected) at Center of Section Goodnews Bay Phase C : Nominal = 0 kvar Actual = 0 kvar ELECTRIC POWER SYSTEMS PAGE 14 OF 44 6/5/2002 West Section Name DONLIN MINE PROJECT — FEASIBILITY STUDY FOI IOI III IIIT III III II TOI TOIT Te tte tek eekeneenee § TLoad-Flow Results For West *****ssex* JUSSI OIG IOI ISIE SII ISIE III III IIIT I ttt Section Load Load Into Section -- 120V Base -- Dist Nom $V Phs Ldg Volt Accm Volt K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level Section Feeder Feeder Feeder Atmautluak Kasigluk/Nunapi Capacitor Newtok Generator Chevak Hooper Bay Capacitor Scammon Bay Capacitor Corning Corning (Wye-Gnd (Module 1 Phase B : Corning 138.0 0.0 A 0 0 0 0 120.0 B 2983-37 37 -100 120.0 c 0 0 0 0 120.0 18.0138.0 0.0 B 307 190 5 11 2983 Qo 37-100 0.5 0.5 119.5 25.0138.0 0.0 B 1274 =o 16 10 2661 -182 34 -100 0.4 0.9 119.1 Connected) at Center of Section Kasigluk/Nunapi 400 kvar/Ph) {Module 2 400 kvar/Ph) Nominal = 800 kvar Actual = 792 kvar 90.0138.0 0.0 B-1762 148 4 5 1383 -152 18 -99 1.9 2.8 117.2 2MW 80kV Wind Single-Phase CONST. PQ On Phase B At Center of Section Newtok Phase B : Corning 1 Corning 1 (Wye-Gnd (Module 1 Phase B : Corning 1 (Wye-Gnd (Module 1 Phase B : ELECTRIC POWER SYSTEMS 119.2 V 25 Amps 2000 kw -0 kvar 45.0138.0 0.0 B 808 501 12 11 3105 -34 40 -100 1.8 4.7 115.3 70.0138.0 0.0 B 1180 -8 15 4 1184 -196 16 -99 1.0 5.7 124.3 Connected) at Center of Section Hooper Bay 400 kvar/Ph) {Module 2 400 kvar/Ph) Nominal = 800 kvar Actual = 740 kvar 70.0138.0 0.0 B 1060 -85 14 4 1063 -280 14 -97 0.8 5.4 114.6 Connected) at Center of Section Scammon Bay 400 kvar/Ph) (Module 2. 400 kvar/Ph) Nominal = 800 kvar Actual = 742 kvar PAGE 15 OF 44 6/5/2002 39.4-265.7 49.2 -59.7 4.1-187.2 3.3-194.4 oo B Feeder Feeder Feeder Atmautluak Kasigluk/Nu Newtok Chevak Hooper Bay Scammon Bay DONLIN MINE PROJECT — FEASIBILITY STUDY FOCI III III III III III IOI IO IOI IOI IIIT II II SAI ID: Load-Flow Results For Southwest ******#### JOSIE ISITE ISIE IEICI IEICE ITO ICI SISTA ISI TT tt te FOI Ree Southwest Section Name Feeder Feeder Feeder Napakiak Tuntutuliak Kongiganak Kwigillingok Kipnuk Capacitor Generator Chefornak Nightmute Toksook Bay Capacitor Tununak Section Load Load Into Section -- 120V Base -- 0.1 -44.5 aagaaaqawpy aaa Feeder Napakiak Tuntutuliak Kongiganak Kwigillingo Kipnuk Chefornak Nightmute Toksook Bay Tununak Phase Dist Nom $V Phs Ldg Volt Accm Volt Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps’ pf Drop Drop Level 138.0 0.0 A 0 0 0 0 120.0 B 0 0 0 0 120.0 c 1647 43 21 100 120.0 Corning 8.0138.0 0.0 C 333 206 5 6 1647 43° 21 100 0.2 0.2 119.8 Corning 48.0138.0 0.0 C 398 247 6 5 1312 -103 17-100 0.8 1.0 119.0 Corning 73.0138.0 0.0 Cc 409 254 6 3 908 -20 11-100 0.5 1.5 118.5 Corning 83.0138.0 0.0 C 237 146 4 2 497 -54 6 -99 0.0 1.5.118.5 Corning 118.0138.0 0.0 C-1258 69 9 1 260 -107 4 -92 1.3 2.8 117.2 (Wye-Gnd Connected) at Center of Section Kipnuk (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase C : Nominal = 400 kvar Actual = 391 kvar 2MW 80kV Wind Single-Phase CONST. PQ On Phase C At Center of Section Kipnuk Phase C: 118.6 V 25 Amps 2000 kW 0 kvar Corning 133.0138.0 0.0 Cc 353 219 5 6 1509 75 19 100 0.4 3.2 116.8 Corning 158.0138.0 0.0 Cc 243 150 4 4 1152 -34 15-100 0.5 3.7 116.3 Corning 173.0138.0 0.0 c* 589 -10 8 3 906 16 12 100 0.5 4.2 115.8 (Wye-Gnd Connected) at Center of Section Toksook Bay (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase C : Nominal = 400 kvar Actual = 375 kvar Corning 178.0138.0 0.0 c 315 195 5 1 315 151 5: 90 0.1 4.3 115.7 PAGE 16 OF 44 6/5/2002 ELECTRIC POWER SYSTEMS North Section Name Feeder Feeder Feeder Akiachak Capacitor Akiak Capacitor Tuluksak Capacitor L Kalskag Capacitor L Russian Mission Capacitor L Marshall Capacitor L_ Pilot Station Capacitor L St Mary's/Pitka Capacitor L Mt Village Capacitor L_ Sheldon Point Capacitor Generator DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III III III II ITI II IOI IIT TI TIT ISA ID ***eeeeee* ~Load-Flow Results For North FEISS IIIS IIIT EIEIO IOI ISITE ITO I ee Section Load Load Into Section Phase Dist Nom %V Phs Ldg Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps 138.0 0.0 A 6371 651 B 0 0 c 0 0 Corning 10.0138.0 0.0 A 519 -74 7 23° 6371 651 (Wye-Gnd Connected) at Center of Section Akiachak (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 396 kvar Corning 18.0138.0 0.0 A 438 -20 6 21 5815 491 (Wye-Gnd Connected) at Center of Section Akiak (Module 1 200 kvar/Ph) (Module 2. 100 kvar/Ph) Phase A: Nominal = 300 kvar Actual = 291 kvar Corning 35.0138.0 0.0 A 276 -19 3. 20 5353 363 (Wye-Gnd Connected) at Center of Section Tuluksak (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 190 kvar Corning 75.0138.0 0.0 A 499 -59 6 19 5031 130 (Wye-Gnd Connected) at Center of Section Kalskag (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 369 kvar Corning 120.0138.0 0.0 A 325 23 4 13 3394 =55 (Wye-Gnd Connected) at Center of Section Russian Mission (Module 1 100 kvar/Ph) (Module 2. 100 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 178 kvar Corning 145.0138.0 0.0 A 369 5a 5 12 3017 -149 (Wye-Gnd Connected) at Center of Section Marshall (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 174 kvar Corning 170.0138.0 0.0 A 583 190 8 10 2625 -203 (Wye-Gnd Connected) at Center of Section Pilot Station (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 172 kvar Corning 180.0138.0 0.0 A 504 141 7 8 2025 -345 (Wye-Gnd Connected) at Center of Section St Mary's/Pitka (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 171 kvar Corning 195.0138.0 0.0 A 932 63 13 6 1516 -444 (Wye-Gnd Connected) at Center of Section Mt Village (Module 1 300 kvar/Ph) (Module 2 300 kvar/Ph) Phase A: Nominal = 600 kvar Actual = 514 kvar Corning 245.0138.0 0.0 A-1784 130 3 3 S81 -418 (Wye-Gnd Connected) at Center of Section Sheldon Point Phase A: Nominal = 0 kvar Actual = 0 kvar 74 69 65 45 41 36 28 21 10 TR tok tte -- 120V Base -- Volt Accm Volt pf Drop Drop Level 99 1.4 100 0.9 100 1.5 100 2.5 -100 1.7 -100 0.7 -100 0.5 -99 -0.0 -96 0.0 -81 -0.4 1.4 2.3 Bad) 6.3 8.0 8.7 9.2 9.2 9.3 8.8 120.0 120.0 120.0 118.6 117.7 116.1 113.7 112.0 111.3 110.8 110.8 110.7 111.2 2MW 80kV Wind Single-Phase CONST. PQ On Phase A At Center of Section Sheldon Point Phase A: 111.7 V 27 Amps 1999 kW 3 kvar ELECTRIC POWER SYSTEMS PAGE 17 OF 44 Losses a 36.6 233.9 24.8 148.5 45.2 250.9 95.9 507.0 51.3 72.8 23.2 -1.4 17.5 -47.4 4.1 -43.0 3.5 -89.1 18.7-254.1 Phs Cfg PrPawpy Feeder Feeder Feeder Akiachak Akiak Tuluksak Kalskag Russian Mis Marshall Pilot Stati St Mary's/P Mt Village Sheldon Poi DONLIN MINE PROJECT — FEASIBILITY STUDY North Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $v Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section L Alakanuk Corning 255.0138.0 0.0 A 625 43 8 9 2347 -293 32 -99 0.2 9.0 111.0 5.4 -30.5 A Alakanuk Capacitor (Wye-Gnd Connected) at Center of Section Alakanuk (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 344 kvar L Emmonak Corning 260.0138.0 0.0 A 1082 -15 15 7 1717 -306 24 -98 0.1 9.1 110.9 1.0 -25.2 A Emmonak Capacitor (Wye-Gnd Connected) at Center of Section Emmonak (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 686 kvar L Kotlik Corning 300.0138.0 0.0 A 631 47 9 3 634 -266 9 -92 0.6 9.7:110.3 2.2-312.9 A Kotlik Capacitor (Wye-Gnd Connected) at Center of Section Kotlik (Module 1 200 kvar/Ph) (Module 2. 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 344 kvar L Aniak Corning 100.0138.0 0.0 A 1039 -77 14 4 1043 -264 14-97: «20.8 «+7.1 :112.9 3.5-187.6 A Aniak Capacitor (Wye-Gnd Connected) at Center of Section Aniak (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 720 kvar ELECTRIC POWER SYSTEMS PAGE 18 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY 9 Appendix B-3 : Case 3 - 80 kV SWGR, No mine, 8 MW Wind DPA/G 5.1 is a Product of Stoner Associates (c)1998 Project : Donlin Mine Study - 80 kV Licensed To : Electric Run Time : 05/16/02 Power Systems, Inc. 09:09:12 Application : Load-Flow Analysis Options: Analysis Options, Messages, Warnings, and Errors: Using By-Phase Model Convergence took 25 iterations with a convergence factor of 0.5000 Exceptions : H = Voltage > 126.0 L = Voltage < 114.0 C = Cond. Loading > 75% T = Tran. Loading > 95% FOI III III III III IOI IOI III ITT TIT I I IO S OI AIAII AA 3 A *akeeeeeee* ~~ Feeder and Substation Three-Phase Summary ********** FOSS ISIS ISIS ISI IIIT IOISIO ITI III IIT IIIT IIIT Rt tk kVA pf Amps Cust kW Loss Pct Loss Feeders of Bethel Substation East 677 91.1% 3 0 0 0.1% South 1695 -99.4% 7 0 12 0.7% West 2983 -100.0% 12 0 115 3.8% Southwest 1648 100.0% 7 0 27 1.6% North 5797 -99.5% 24 0 236 4.1% TOTAL 12709 -99.9% 0 390 3.1% FOI III III TO IOI ICIS ISIS IIIT III II III IOI III TIT te ****eeeee* Feeder and Substation By-Phase Summary ********** JESSIE IEE ISIC ISHII IOS IO IESE TO IO TOTTI II III TIT =A/AB == == B/BG == =='C/CAi== [=== ANPS --— CUSTOMERS KW LOSSES PCT kVA pf kVA pf kVA PF A B c A B c A B Cc Loss Feeders of Bethel Substation ELECTRIC POWER SYSTEMS East 0 0.0% 677 91.1% O 0.0% 0 8 0 0 0 0 0 0 0 0.1% South 0 0.0% 0 0.0% 1695 -99.4% 0 0 21 0 0 0 0 0 12 0.7% West 0 0.0% 2983 -100.0% 0 0.0% 0 37 0 0 0 0 o 115 0 3.8% Southwest 0 0.0% 0 0.0% 1648 100.0% 0 0 21 0 0 0 0 0 27) 1.6% North 5797 -99.5% 0 0.0% 0 0.0% 73 0 0 0 0 0 236 0 0 4.1% TOTAL 5797 -99.5% 3607 99.8% 3335 -99.9% 0 0 0 236 115 38 3.1% PAGE 19 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III III IIIT IOI IOI IOI OSI IOS IOS IR A teeeeeeee* ~ Peeder Mininimum / Maximum Summary ********** FOGGIA IIIT TI I IIIA A Maximum Section Drop Maximum Loss Pct Minimum Volts Max Conduct. Loading Section Max Section Max Section Min Section Max Feeders of Bethel Substation East A Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 A B Kwethluk 0.4 Kwethluk 100.0 Kwethluk 119.6 Kwethluk 2.4 B c Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 C South A Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 A B Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 B @ Quinhagok 0.2 Eek 51.1 Napaskiak 120.0 Napaskiak 6.1 C West A Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 A B Newtok 1.9 Chevak 42.9 Hooper Bay 114.3 Chevak 11.4 B Cc Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 C Southwest A Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 A B Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 B ic Kipnuk 1.3 Kipnuk 32.8 Tununak 115.7 Napakiak 5.9 C North A Aniak 0.8 Kalskag 29.3 Akiak 119.8 Akiachak 20.8 A B Akiachak 0.0 Akiachak 0.0 Akiachak 120.0 Akiachak 0.0 B c Akiachak 0.0 Akiachak 0.0 Akiachak 120.0 Akiachak 0.0 C ELECTRIC POWER SYSTEMS PAGE 20 OF 44 6/5/2002 East Section Name DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III III II IIIT I IOI I IIIT I te Load-Flow Results For East FOI III III III III III III TI IIIT IOI III I Ss. FI I te FOI I tk te -- 120V Base -- Volt Accm Volt Drop Drop Level Section Load Load Into Section $V Phs Imb Cfg Phase Dist Nom Conduct K FT kVLL Ldg kW kvar Amps Pct kW kvar Amps Losses Phs KW KVAR Cfg Section Feeder Feeder Feeder Kwethluk Capacitor South Section Name 138.0 0.0 A 0 0 0 0 120.0 B 616 279 8 91 120.0 c 0 0 0 0 120.0 Corning 11.0138.0 0.0 B 616 381 9 2 616 279 8 91 0.4 0.4 119.6 (Wye-Gnd Connected) at Center of Section Kwethluk Phase B : Nominal = 0 kvar Actual = 0 kvar FEISS III SII SISI IIIT III IIIT III It **eeeeee%* ~Load-Flow Results For South *******#*# FOI SII I CII III IIS ISIE IOI III II tr Section Load Load Into Section -- 120V Base -- Phase Dist Nom $V Phs Ldg Volt Accm Volt Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps Drop Drop Level 0.5-101.8 waowp Feeder Feeder Feeder Kwethluk Section Feeder Feeder Feeder Napaskiak Capacitor Eek Capacitor Quinhagok Capacitor Goodnews Bay Capacitor ELECTRIC POWER SYSTEMS 138.0 0.0 A 0 0 0 0 120.0 B 0 0 0 0 120.0 c 1684 -189 21 -99 120.0 Corning 6.0138.0 0.0 Cc 414 256 6 6 1684 -189 21 -99 0.0 0.0 120.0 (Wye-Gnd Connected) at Center of Section Napaskiak Phase C : Nominal = 0 kvar Actual = 0 kvar Corning 46.0138.0 0.0 Cc 293 182 4 5 1269 -401 17. -95 -0.4 -0.3 120.3 (Wye-Gnd Connected) at Center of Section Eek Phase C : Nominal = 0 kvar Actual = 0 kvar Corning 86.0138.0 0.0 C 640 396 9 4 970 -246 13. -97 0.2 -0.2 120.2 (Wye-Gnd Connected) at Center of Section Quinhagok Phase C : Nominal = 0 kvar Actual = 0 kvar Corning 136.0138.0 0.0 C 326 202 5 2 327-282 5 -76 -0.0 -0.2 120.2 (Wye-Gnd Connected) at Center of Section Goodnews Bay Phase C : Nominal = 0 kvar Actual = 0 kvar PAGE 21 OF 44 6/5/2002 1.5 -44.4 5.9-337.0 3.4-360.3 0.7-483.7 a Feeder Feeder Feeder Napaskiak Eek Quinhagok Goodnews Ba DONLIN MINE PROJECT — FEASIBILITY STUDY FOI IIIT IIT I IIIS IIIT TOTTI TIT tte seeeeEERSS ~ Load-Flow Results For West **###*e+e% JE ISIS IOS ISIE IU IO ISIS IEE IOI IO IOI TAI TOTO TOIT West Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V =Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 2983 =37 37 -100 120.0 B Feeder Feeder c 0 0 0 0 120.0 C Feeder Atmautluak Corning 18.0138.0 0.0 B 307 190 5 11 2983 -37 37-100 0.5 0.5 119.5 14.1 -46.0 B Atmautluak Kasigluk/Nunapi Corning 25.0138.0 0.0 B 1274 <3 16 10 2661 -182 34-100 0.4 0.9 119.1 4.6 -26.0 B Kasigluk/Nu Capacitor (Wye-Gnd Connected) at Center of Section Kasigluk/Nunapi (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 792 kvar Newtok Corning 90.0138.0 0.0 B-1762 148 4 5 1383 -152 18 -99 1.9 2.8 117.2 39.4-265.7 B Newtok Generator 2MW 80kV Wind Single-Phase CONST. PQ On Phase B At Center of Section Newtok Phase B: 119.2 V 25 Amps 2000 kW -0 kvar Chevak Corning 145.0138.0 0.0 B 808 501 12 11 3105 -34 40 -100 +8 4.7.115.3 49.2 -59.7 Chevak Hooper Bay Corning 170.0138.0 0.0 B1180 -8 15 4 1184 -196 16 -99 1.0 5.7 114.3 4,1-187.2 B Hooper Bay Capacitor (Wye-Gnd Connected) at Center of Section Hooper Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 740 kvar Scammon Bay Corning 170.0138.0 0.0 B 1060 -85 14 4 1063 -280 14 -97 0.8 5.4 114.6 3.3-194.4 B Scammon Bay Capacitor (Wye-Gnd Connected) at Center of Section Scammon Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 742 kvar w ELECTRIC POWER SYSTEMS PAGE 22 OF 44 6/5/2002 Southwest Phase Section Name Conduct Feeder Feeder Feeder Napakiak Corning Tuntutuliak Corning Kongiganak Corning Kwigillingok Corning Kipnuk Corning 1 Capacitor (Wye-Gnd (Module 1 Phase C : Dist Nom K FT kVLL 8.0138. 48.0138. 73.0138. 83.0138. 18.0138.0 cooo DONLIN MINE PROJECT — FEASIBILITY STUDY FRI III II TIT II III IIIT IOI IOI OSI OOS OTS AIA IAD +x**e4e%4% ~Load-Flow Results For Southwest ********#* FOI III IOI III ISITE TI III IIIT TOI I Section Load Load Into Section -- 120V Base -- $V Phs Ldg Volt Accm Volt Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level 0.0 A 0 0 0 0 B 0 0 0 0 c 1647 43 21 100 0.0 C 333 206 5 6 1647 43 21 100 0.2 0.0 C 398 247 6 5 1312 -103 17-100 0.8 0.0 Cc 409 254 6 3 908 -20 11-100 0.5 0.0 C 237 146 4 2 497 -54 6 -99 0.0 0.0 C-1258 69 9 1 260 -107 4 -92 1.3 Connected) at Center of Section Kipnuk 200 kvar/Ph) (Module 2 200 kvar/Ph) Nominal 400 kvar Actual = 391 kvar Generator 2MW 80kV Wind Single-Phase CONST. PQ On Phase C At Center of Section Kipnuk Phase C : Chefornak Corning 133.0138.0 0.0 Cc 353 219 5 6 1509 75 19 100 Nightmute Corning 158.0138.0 0.0 Cc 243 150 4 4 1152 -34 15 -100 Toksook Bay Corning 173.0138.0 0.0 c 589 -10 8 3 906 16 12 100 118.6 V 25 Amps 2000 kW 0 kvar ooo One Capacitor (Wye-Gnd Connected) at Center of Section Toksook Bay 200 kvar/Ph) (Module 2 200 kvar/Ph) (Module 1 Phase C : Nominal 400 kvar Actual = 375 kvar Tununak Corning 178.0138.0 0.0 c 315 195 5 1 315 151 5 90 0.1 ELECTRIC POWER SYSTEMS PAGE 23 OF 44 6/5/2002 NERRHO ww NaN 4 @OuUUdN 3 120.0 120.0 120.0 119.8 119.0 118.5 118.5 117.2 116.8 116.3 115.8 115.7 rww DOrRar Losses KW KVAR «1 -44.5 Phs Cfg aagagaaawp aaa Section Feeder Feeder Feeder Napakiak Tuntutuliak Kongiganak Kwigillingo Kipnuk Chefornak Nightmute Toksook Bay Tununak Tre a DlCU!””DhCULULD!DhU Umm North Section Name DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III TIT I IS IIOIGIIITIIIITITI I tte ****seee%* ~~ Load-Flow Results For North FOI III III ITI TIT I OI IIIIIIIIOIITIIIOTI Section Load Load Into Section Phase Dist Nom tv Phs Ldg Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps TOTO Rt tk -- 120V Base -- Volt Accm Volt pf Drop Drop Level Losses KW KVAR Phs Cfg Section Feeder Feeder Feeder Akiachak Capacitor Akiak Capacitor Tuluksak Capacitor Kalskag Capacitor Russian Mission Capacitor Marshall Capacitor Pilot Station Capacitor St Mary's/Pitka Capacitor Mt Village Capacitor Sheldon Point Capacitor Generator 138.0 0.0 A 5770 -561 B 0 0 c 0 0 Corning 10.0138.0 0.0 A 529 -72 7 21 #5770 -561 (Wye-Gnd Connected) at Center of Section Akiachak (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 400 kvar Corning 18.0138.0 0.0 A 453 -18 6 19 5211 -658 (Wye-Gnd Connected) at Center of Section Akiak (Module 1 200 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 300 kvar Actual = 299 kvar Corning 35.0138.0 0.0 A 295 -17 4 17 4738 -738 (Wye-Gnd Connected) at Center of Section Tuluksak (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 200 kvar Corning 75.0138.0 0.0 A 567 -55 7 16 4408 -866 (Wye-Gnd Connected) at Center of Section Kalskag (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 408 kvar Corning 120.0138.0 0.0 A 387 32 5 10 2586 -738 (Wye-Gnd Connected) at Center of Section Russian Mission (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 208 kvar Corning 145.0138.0 0.0 A 448 69 6 8 2171 -559 (Wye-Gnd Connected) at Center of Section Marshall (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 209 kvar Corning 170.0138.0 0.0 A 716 234 9 6 1713 -468 (Wye-Gnd Connected) at Center of Section Pilot Station (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 210 kvar Corning 180.0138.0 0.0 A 621 175 8 4 990 -507 (Wye-Gnd Connected) at Center of Section St Mary's/Pitka (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 210 kvar Corning 195.0138.0 0.0 A 1153 80 14 2 368 -590 (Wye-Gnd Connected) at Center of Section Mt Village (Module 1 300 kvar/Ph) (Module 2 300 kvar/Ph) Phase A: Nominal = 600 kvar Actual = 635 kvar Corning 245.0138.0 0.0 A-3732 159 4 3-785 -521 (Wye-Gnd Connected) at Center of Section Sheldon Point Phase A: Nominal = 0 kvar Actual = 0 kvar 73 -100 0 0 0 0 73 -100 66 -99 60 -99 56 -98 33-96 28 -97 22 -96 14-89 9 -53 12 83 0.2 0.2 0.0 0.2 -0.3 -O.1 -0.8 -4.1 120.0 120.0 120.0 119.8 119.8 120.1 121.2 122.3 122.6 122.8 123.0 123.2 124.1 2MW 80kV Wind Single-Phase CONST. PQ On Phase A At Center of Section Sheldon Point Phase A: 124.6 V 48 Amps 3999 kW 7 kvar ELECTRIC POWER SYSTEMS PAGE 24 OF 44 29.5 169.3 19.4 97.9 34.3 144.4 69.2 228.2 27.1-210.5 10.5-159.3 6.3-195.3 0.7 -92.2 0.3-148.0 23.5-314.7 raw, A A Feeder Feeder Feeder Akiachak Akiak Tuluksak Kalskag Russian Mis Marshall Pilot Stati St Mary's/P Mt Village Sheldon Poi DONLIN MINE PROJECT — FEASIBILITY STUDY North Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $v Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Alakanuk Corning 255.0138.0 0.0 A 779 54 9 10 2924 -366 36 -99 0.2 -3.9 123.9 6.9 -38.0 A Alakanuk Capacitor (Wye-Gnd Connected) at Center of Section Alakanuk (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 428 kvar Emmonak Corning 260.0138.0 0.0 A 1347 -18 16 8 2138 -382 26 -98 0.1 -3.8 123.8 1.6 -31.4 A Emmonak Capacitor (Wye-Gnd Connected) at Center of Section Emmonak (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 854 kvar Kotlik Corning 300.0138.0 0.0 A 786 58 10 3 789 -332 10 -92 0.6 -3.1 123.1 2.9-389.8 A Kotlik Capacitor (Wye-Gnd Connected) at Center of Section Kotlik (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 429 kvar Aniak Corning 100.0138.0 0.0 A 1182 -87 15 4 1186 -301 15 -97 0.8 -0.4 120.4 3.9-213.3 A Aniak Capacitor (Wye-Gnd Connected) at Center of Section Aniak (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 819 kvar ELECTRIC POWER SYSTEMS PAGE 25 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY 40 Appendix B-4 : Case 4 - 80 kV SWGR, Donlin Mine, 30 MW Wind (15 MW output) DPA/G 5.1 is a Product of Stoner Associates (c)1998 Project : Donlin Mine Study - 80 kv Licensed To : Electric Power Systems, Inc. Run Time : 05/16/02 10:57:32 Application : Load-Flow Analysis Options: Using By-Phase Model Convergence took 30 iterations with a convergence factor of 0.5000 Exceptions : H = Voltage > 126.0 L = Voltage < 114.0 C = Cond. Loading > 75% T = Tran. Loading > 95% FOI III II III III III III IIIT III TOI OIRO IOI IAT A A ***eeeee%% Feeder and Substation Three-Phase Summary ********** JOBE S SESE SISSIES IO ISIS OIIE IOI IO IO IGT ITT IIR i tee KVA pf Amps Cust kW Loss Pct Loss Feeders of Bethel Substation 138 Line 63834 -99.2% 267 0 4640 7.3% East 677 91.1% iS 0 0 0.1% South 1695 -99.4% 7 0 12 0.7% West 198 -99.0% 1 0 103 52.8% Southwest 198 47.6% a 0 26 27.4% TOTAL 66232 -99.3% 0 4782 7.3% FOI III III III III RII III III ITI IIIT ITI tte ***eeeee%* Feeder and Substation By-Phase Summary *******##* JOTI III ISI IIIS ISI IIIS IIIT TET ITT III TART TAIT ATRIA -- A/AB -- -- B/BC -- -- C/CA -- ==== BRS === CUSTOMERS KW LOSSES PCT kVA pf kVA pf kVA PF A B c A B c A B Cc Loss Feeders of Bethel Substation 138 Line 21312 -98.9% 21222 -99.4% 21311 -99.4% 267 266 267 0 0 0 1560 1419 1662 7.3% East 0 0.0% 677 91.1% 0 0.0% 0 8 0 0 0 0 0 0 0 0.1% South Oo 0.0% 0 0.0% 1695 -99.4% 0 o 21 0 0 0 0 0 12. 0.7% West 0 0.0% 198 -99.0% Oo 0.0% 0 2 0 0 0 0 0 103 0 52.8% Southwest 0 0.0% 0 0.0% 198 47.6% 0 0 2 0 0 0 0 O 26 27.4% TOTAL 21312 -98.9% 22005 -99.6% 22932 -99.3% 0 0 0 1560 1523 1699 7.3% ELECTRIC POWER SYSTEMS PAGE 26 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III III III III III TO II III III SII II A te Feeder Mininimum / Maximum Summary JOISTS IO SISOS SEITE ESI III II III IIe FOCI Ie tek FOR III I Maximum Section Drop Maximum Loss Pct Minimum Volts Max Conduct. Loading Section Max Section Max Section Min Section Max Feeders of Bethel Substation 138 Line A Donlin Mine 2.9 Donlin Mine 13.8 Donlin Mine 116.1 Akiachak 29.7 A B Donlin Mine 2.5 Donlin Mine 12.6 Donlin Mine 116.0 Akiachak 29.6 B c Donlin Mine 2.6 Donlin Mine 13.0 Donlin Mine 114.3 Akiachak 29.7) C East A Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 A B Kwethluk 0.4 Kwethluk 100.0 Kwethluk 119.6 Kwethluk 2.4 B c Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 C South A Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 A B Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 B c Quinhagok 0.2 Eek 51.1 Napaskiak 120.0 Napaskiak 6.1 C West A Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 A B Chevak 1.9 Chevak 50.5 Hooper Bay 117.9 Chevak 11.8 B c Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 C Southwest A Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 A B Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 B c Toksook Bay 0.3 Kipnuk 49.4 Napakiak 120.1 Chefornak 6.2 C ELECTRIC POWER SYSTEMS PAGE 27 OF 44 6/5/2002 a — — — — — — — — — — — — — — == = 138 Line Section Name Feeder Feeder Feeder Akiachak Akiachak Akiachak Capacitor Akiak Akiak Akiak Tuluksak Tuluksak Tuluksak Capacitor Kalskag Kalskag Kalskag Capacitor Russian Mission Capacitor Marshall Pilot Station Capacitor St Mary's/Pitka Mt Village Capacitor ELECTRIC POWER SYSTEMS DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III III IIIT TE Iti iti tte tek Ft tok Load-Flow Results For 138 Line eset eters FRI III III III III IIIT ITI Tt tek Section Load Ldg kW kvar Amps Pct $v Phs Imb Cfg Phase Dist Nom Conduct K FT kVLL 138.0 0.0 A 21078 -3149 B 21096 -2315 c 21180 -2351 A 0 0 QO 30 21078 -3149 B 529 328 8 30 21096 -2315 c 0 0 0 30 21180 -2351 (Wye-Gnd Connected) at Center of Section Akiachak Phase A: Nominal = 0 kvar Actual = 0 kvar Phase B : Nominal = 0 kvar Actual = 0 kvar Phase C : Nominal = 0 kvar Actual = 0 kvar 795 ACSR 95.0138.0 0.2 A 0 0 20988 -3240 B 452 280 20468 -2719 0 0 21076 -2446 0 -199 20917 -3317 0 -199 28 19945 -3040 Cc 290 -215 30 20989 -2519 (Wye-Gnd Connected) at Center of Section Tuluksak (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Phase B : Nominal = 200 kvar Phase C : Nominal = 400 kvar Actual = 395 kvar 795 ACSR396.0138.0 0.9 A 551 -56 7 29 20767 -3283 B 0 -396 5 28 19808 -2888 c 0 -389 5 29 20505 -2453 (Wye-Gnd Connected) at Center of Section Kalskag (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Phase B : Nominal = 400 kvar Actual = 396 kvar Phase C : Nominal = 400 kvar Actual = 389 kvar Corning 441.0138.0 0.0 A 384 -276 6 4 284 -1004 (Wye-Gnd Connected) at Center of Section Russian Mission Phase A: Nominal = 500 kvar Actual = 514 kvar Corning 466.0138.0 0.0 A 444 276 6 1 = -103 Corning 491.0138.0 0.0 A 704 -398 10 2 -547 (Wye-Gnd Connected) at Center of Section Pilot Station (Module 1 400 kvar/Ph) (Module 2. 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 835 kvar Corning 501.0138.0 0.0 A 607 376 iS 5) —1253 Corning 516.0138.0 0.0 A 1117 75 14 7 -1861 (Wye-Gnd Connected) at Center of Section Mt Village (Module 1 300 kvar/Ph) (Module 2 300 kvar/Ph) Phase A: Nominal = 600 kvar Actual = 617 kvar 795 ACSR 52.8138.0 0.1 30 29 30 c 795 ACSR184.8138.0 0.4 A 30 B mWWOor)d Actual = Actual = 199 kvar 199 kvar Actual = 398 kvar -302 -329 309 19 PAGE 28 OF 44 kW kvar Amps 267 266 267 267 266 267 267 260 267 266 254 266 264 252 262 13 - 16 23 Load Into Section -99 -99 oo =<39 =99 -99 oo oo =99 -99 09 -99 =99 =o wow an -97 -100 -- 120V Base -- Volt Accm Volt pf Drop Drop Level ooo oooooo ANRPNER wwe roooCoo ooo wwe FOANU aE NRO won eek 120.0 120.0 120.0 119.9 119.7 119.7 119.9 119.6 119.5 119.8 119.4 118.9 119.5 119.0 117.7 121.7 122.1 121.8 121.6 121.3 91.3 76.3 94.5 89.9 98.8 104.5 71.4 71.2 87.4 76.1 40.8 73.1 149.8 165.6 136.5 46.9 193.5 149.1 350.4 347.6 317.2 90.8 428.7 285.0 Phs Cfg Section A Feeder B Feeder C Feeder A Akiachak B Akiachak C Akiachak Akiak Akiak Akiak Tuluksak Tuluksak Tuluksak aQwrawp Kalskag Kalskag Kalskag aQawmPr A Russian Mis A Marshall A Pilot Stati A St Mary's/P A Mt Village DONLIN MINE PROJECT — FEASIBILITY STUDY 138 Line Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Sheldon Point Corning 566.0138.0 0.0 A-5748 = 47 3 11 -2983 49 37-100 0.9 -0.5 120.5 39.3-150.9 A Sheldon Poi Capacitor (Wye-Gnd Connected) at Center of Section Sheldon Point (Module 1 100 kvar/Ph) Phase A: Nominal = 100 kvar Actual = 104 kvar Generator 10MW 80kV Wind Single-Phase CONST. PQ On Phase A At Center of Section Sheldon Point Phase A: 122.2 V 74 Amps 6000 kW 5 kvar Alakanuk Corning 576.0138.0 0.0 Bo 728) 149 S10 2726) tos 34. 100. 10.6 0.2) 219.81 6-7, 36.4) A Alakanuk Capacitor (Wye-Gnd Connected) at Center of Section Alakanuk (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 402 kvar Emmonak Corning 581.0138.0 0.0 A 1257 381 Adee eo Ou 140 25 100 0.3 0.5 119.5 1.4 -30.4 A Emmonak Capacitor (Wye-Gnd Connected) at Center of Section Emmonak (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 398 kvar Kotlik Corning 621.0138.0 0.0 A) 781) | 154 CO cE 3) 10 -96 0.8 1.2 118.8 2.5-363.9 A Kotlik Capacitor (Wye-Gnd Connected) at Center of Section Kotlik (Module 1 300 kvar/Ph) Phase A: Nominal = 300 kvar Actual = 299 kvar Aniak 795 ACSR528.0138.0 1.2 A 0 -495 6 26 19582 -2570 249 -99 0.4 0.9 119.1 195.7 76.5 A Aniak Aniak B 0 -490 6 26 19491 -2583 249 -99 0.5 1.5 118.5 209.8 53.5 B Aniak Aniak C1113 -363 15 29 20077 -2348 259 -99 0.8 3.1 116.9 244.4 177.3 C Aniak Capacitor (Wye-Gnd Connected) at Center of Section Aniak (Module 1 500 kvar/Ph) Phase A: Nominal = 500 kvar Actual = 495 kvar Phase B : Nominal = 500 kvar Actual = 490 kvar Phase C : Nominal = 1100 kvar Actual = 1053 kvar Donlin Mine 795 ACSR924.0138.0 1.0 A18743-2342 242 27 19386 -2151 247 -99 2.9 3.9 116.1 642.4 190.4 A Donlin Mine Donlin Mine B18696-2327 242 27 19281 -2146 247 -99 2.5 4.0 116.0 585.3 181.0 B Donlin Mine Donlin Mine C18116-2259 238 27 18719 -2162 243 -99 2.6 5.7 114.3 603.3 96.4 C Donlin Mine Capacitor (Wye-Gnd Connected) at Center of Section Donlin Mine (Module 1 1000 kvar/Ph) (Module 2 1000 kvar/Ph) (Module 3 400 kvar/Ph) Phase A: Nominal = 2400 kvar Actual = 2342 kvar Phase B : Nominal = 2400 kvar Actual = 2327 kvar Phase C : Nominal = 2400 kvar Actual = 2259 kvar ELECTRIC POWER SYSTEMS PAGE 29 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III II III III IOI OI ISO IOI It saeteeee4* ~Load-Flow Results For East ********** JESSIE ISIS IO SII IOI IO IO IO TO IE IO IOI IE III I East Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom %V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 616 279 8 91 120.0 B Feeder Feeder c 0 0 0 0 120.0 C Feeder Kwethluk Corning 11.0138.0 0.0 B 616 381 9 2 616 279 8 91 0.4 0.4 119.6 0.5-101.8 B Kwethluk FI III II III IOI III III ITI III III IOI IOI Tt te saaex4e4e% ~~ Load-Flow Results For South *******##* JEISIO IE IIIS SISSIES EOS IE SEIOI ICICI IOI IOI I IO i South Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 0 0 0 0 120.0 B Feeder Feeder c 1684 -189 21 -99 120.0 C Feeder Napaskiak Corning 6.0138.0 0.0 Cc 414 256 6 6 1684 -189 21 -99 0.0 0.0 120.0 1.5 -44.4 C Napaskiak Eek Corning 46.0138.0 0.0 C 293 182 4 5 1269 -401 17° -95 -0.4 -0.3 120.3 5.9-337.0 Cc Eek Quinhagok Corning 86.0138.0 0.0 Cc 640 396 9 4 970 -246 13 -97 0.2 -0.2 120.2 3.4-360.3 C Quinhagok Goodnews Bay Corning 136.0138.0 0.0 C 326 202 5 2 327 -282 5 -76 -0.0 -0.2 120.2 0.7-483.7 C Goodnews Ba ELECTRIC POWER SYSTEMS PAGE 30 OF 44 6/5/2002 West Section Name Feeder Feeder Feeder Atmaut luak Kasigluk/Nunapi Newtok Capacitor Generator Chevak Hooper Bay Capacitor Scammon Bay Capacitor DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III II II III III II III III IIIT IIIT ITO IO tte cea REERE SS —LOad-Plow Results For West) *******a2% JES EIO EI SSIIISI EIS ISIC IEE IG ITSO IIIT I tt Section Load Load Into Section Phase Dist Nom $V Phs Ldg Conduct K FIT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps) pf 138.0 0.0 A 0 0 0 0 B 196 -28 2 -99 Cc 0 0 0 0 Corning 18.0138.0 0.0 B 309 192 5 1 196 -28 2 -99 Corning 25.0138.0 0. B 1290 799 19 O -114 -46 Zz 93 Corning 90.0138.0 0.0 B-4747 -472 6 6 -1404 -778 20 87 (Wye-Gnd Connected) at Center of Section Newtok (Module 1 300 kvar/Ph) (Module 2 300 kvar/Ph) Phase B : Nominal = 600 kvar Actual = 629 kvar 10MW 80kV Wind Single-Phase CONST. PQ On Phase B At Center of Section Phase B: 122.9 V 61 Amps 5000 kw -0 kvar Corning 145.0138.0 0.0 B 859 532 13 12 3299 =37 41 -100 Corning 170.0138.0 0.0 B 1254 -9 16 5 1258 -208 16 -99 (Wye-Gnd Connected) at Center of Section Hooper Bay (Module 1 400 kvar/Ph) (Module 2. 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 786 kvar Corning 170.0138.0 0.0 B 1126 -91 14 4 1130 -297 15 =97 (Wye-Gnd Connected) at Center of Section Scammon Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 788 kvar ELE iL POWER SYSTEMS PAGE 31 OF 44 6/5/2002 -- 120V Base -- Volt Accm Volt Drop Drop Level i ooo oor ooo OH Newtok 1.9 1.1 1.0 2.1 0.8 1.9 120.0 120.0 120.0 119.9 119.9 120.8 118.9 117.9 118.1 52.2 -63.4 3.5-206.5 ww Atmautluak Kasigluk/Nu Newtok Chevak Hooper Bay Scammon Bay Southwest Section Name Feeder Feeder Feeder Napakiak Tuntutuliak Capacitor Kongiganak Capacitor Kwigillingok Kipnuk Capacitor Generator Chefornak Capacitor Nightmute Toksook Bay Capacitor Tununak Capacitor ELECTRIC POWER SYSTEMS DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III II III III III II IO II IIIS IIS IOS IO Ie Load-Flow Results For Southwest FOI III III III III IIIT OI III III OI IOI SII OI I I FO tO ek FO RR ik Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom %V Phs Ldg Volt Accm Volt Phs kW kvar Amps pf Drop Drop Level KW RKVAR Cfg Section Conduct K FT kVLL Imb Cfg kW kvar Amps Pct 138.0 0.0 A 0 0 0 0 120.0 A Feeder B 0 0 0 0 120.0 B Feeder c -94 -174 2 48 120.0 C Feeder Corning 8.0138.0 0.0 Cc 335 207 5 1 -94 ~-174 2 48 -0.1 -0.1 120.1 0.0 -77.4 C Napakiak Corning 48.0138.0 0.0 c 410 254 6 2 -429 ~-304 w 82 -0.6 -0.7 120.7 0.8-384.9 C Tuntutuliak (Wye-Gnd Connected) at Center of Section Tuntutuliak Phase C : Nominal = 0 kvar Actual = 0 kvar Corning 73.0138.0 0.0 C 427 265 6 3-840 -173 11 98 -0.4 -1.1 121.1 1.6-232.0 Cc Kongiganak (Wye-Gnd Connected) at Center of Section Kongiganak Phase C : Nominal = 0 kvar Actual = 0 kvar Corning 83.0138.0 0.0 Cc 249 153 4 5 -1268 -206 16 99 -0.3 -1.4 121.4 1.4 -86.0 C Kwigillingo Corning 118.0138.0 0.0 C-3200 495 12 5 -1518 -274 19 98 -0.3 -1.7 121.7 12.8-235.7 Cc Kipnuk (Wye-Gnd Connected) at Center of Section Kipnuk Phase C : Nominal = 0 kvar Actual = 0 kvar 10MW 80kV Wind Single-Phase CONST. PQ On Phase C At Center of Section Kipnuk Phase C: 122.1 V 49 Amps 4000 kW 0 kvar Corning 133.0138.0 0.0 Cc 385 32 5 6 1670 -533 22 -95 -0.3 -1.9 121.9 3.8-115.7 C Chefornak (Wye-Gnd Connected) at Center of Section Chefornak (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase C : Nominal = 200 kvar Actual = 206 kvar Corning 158.0138.0 0.0 C 269 166 4 5 1281 -450 17 -94 -0.5 -2.4 122.4 3.8-217.5 Cc Nightmute Corning 173.0138.0 0.0 Cc 656-429 10 4 1008 -399 13 -93 0.3 -2.1 122.1 1.6-137.1 C Toksook Bay (Wye-Gnd Connected) at Center of Section Toksook Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase C : Nominal = 800 kvar Actual = 835 kvar Corning 178.0138.0 0.0 Cc 350 217 $1 351 168 5 90 0.1 -2.0 122.0 0.1 -49.5 Cc Tununak (Wye-Gnd Connected) at Center of Section Tununak Phase C : Nominal = 0 kvar Actual = 0 kvar PAGE 32 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY 11 Appendix B-5 : Case 5 - 80 kV SWGR, No Mine, 18 MW Wind Feeders of Bethel Substation East South West Southwest North TOTAL Feeders of Bethel Substation East South West Southwest North TOTAL FOI III II III IIIT III IIIS IIIS III III IO III tok Feeder and Substation Three-Phase Summary FOI TITIES ISI IOI IIS IIS ITI IIIT ITI II IAI tek ta RRR Ae Re KVA pf Amps Cust kW Loss’ Pct Loss 677 91.1% 3 0 0 0.1% 1695 -99.4% 7 0 12 0.7% 880 99.6% 4 0 dag 12.9% 2391 -95.4% 10 0 102 4.5% 3613 -94.9% 15) 0 107 3.1% 2605 -98.7% 0 333 13.0% FOI II III IOI IOI III III IOI IO IOI IOI III III IIIT IOI It te Feeder and Substation By-Phase Summary FIJI III TOI IOI III III III II III II TTI IOI AI TI I AOA IO II A FOI te FOI te -- A/AB -- -- B/BC -- =- C/CA == CUSTOMERS KW LOSSES PCT kVA pf kVA pf kVA Pr A B c A B Cc Loss 0 0.08 677 91.1% 0 0.0% 0 8 0 0 0 0 0 0 Oo 0.1% 0 0.0% 0 0.0% 1695 -99.4% 0 Oo 21 0 0 0 0 0 12 0.7% 0 0.0% 880 99.6% 0 0.0% 0 ill 0 0 0 0 Oo 113 O 12.9% 0 0.0% 0 0.0% 2391 -95.4% 0 Oo 30 0 0 0 0 0 102 4.5% 3613 -94.9% 0 0.0% 0 0.0% 45 0 0 0 0 0 107 0 O 3.1% 3613 -94.9% 327 -79.6% 797 -74.8% oO 0 0 107 113 113 13.0% FOI III IOI ISTO III IOI III III II III III IOI IIIT Feeder Mininimum / Maximum Summary FOI III IOI II III III III III III IO III III te TR ee FIR te Maximum Section Drop Maximum Loss Pct Minimum Volts Max Conduct. Loading Section Max Section Max Section Min Section Max Feeders of Bethel Substation East A Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 A B Kwethluk 0.4 Kwethluk 100.0 Kwethluk 119.6 Kwethluk 2.4 B c Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 C South A Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 A B Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 B c Quinhagok 0.2 Eek 51.1 Napaskiak 120.0 Napaskiak 6.1 C West A Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 A B Chevak 1.9 Newtok 46.6 Hooper Bay 116.4 Chevak 11.6 B c Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 C Southwest A Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 A B Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 B Cc Tuntutuliak 1.3 Kipnuk 30.1 Tununak 115.9 Kipnuk 13.5 C North A Pilot Station 1.1 Sheldon Point 36.7 Kotlik 118.9 Akiachak 13.0 A B Akiachak 0.0 Akiachak 0.0 Akiachak 120.0 Akiachak 0.0 B c Akiachak 0.0 Akiachak 0.0 Akiachak 120.0 Akiachak 0.0 C ELECTRIC POWER SYSTEMS PAGE 33 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III IIIS IOI ISIC III TOTO II IOI I Load-Flow Results For East FI III III III II III IOI IOI III III IIIS TOI IOI ISI OI I FIO III tok FOI I tote -- 120V Base -- Losses Volt Accm Volt pf Drop Drop Level Section Load Load Into Section Ldg kW kvar Amps Pct East Phs KW KVAR Cfg Phase Dist Nom sv Phs Conduct K FT kVLL Imb Cfg Section Name kW kvar Amps Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 616 279 8 91 120.0 B Feeder Feeder c 0 0 0 0 120.0 C Feeder Kwethluk Corning 11.0138.0 0.0 B 616 381 9 2 616 279 8 91 0.4 0.4 119.6 0.5-101.8 B Kwethluk Capacitor (Wye-Gnd Connected) at Center of Section Kwethluk Phase B : Nominal = 0 kvar Actual = 0 kvar FOGG I IIIS ISIS TIO IOI II tet *eeeeaeaee ~Load-Flow Results For South ********** FOIE IIIT ISO IITA III TI TAI South Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 0 0 0 0 120.0 B Feeder Feeder c 1684 -189 21 -99 120.0 C Feeder Napaskiak Corning 6.0138.0 0.0 C 414 256 6 6 1684 -189 21 -99 0.0 0.0 120.0 1.5 -44.4 C Napaskiak Capacitor (Wye-Gnd Connected) at Center of Section Napaskiak Phase C : Nominal = 0 kvar Actual = 0 kvar Eek Corning 46.0138.0 0.0 C 293 182 4 5 1269 -401 17. -95 -0.4 -0.3 120.3 5.9-337.0 Cc Eek Capacitor (Wye-Gnd Connected) at Center of Section Eek Phase C : Nominal = 0 kvar Actual = 0 kvar Quinhagok Corning 86.0138.0 0.0 Cc 640 396 9 4 970 -246 13 -97 0.2 -0.2 120.2 3.4-360.3 C Quinhagok Capacitor (Wye-Gnd Connected) at Center of Section Quinhagok Phase C : Nominal = 0 kvar Actual = 0 kvar Goodnews Bay Corning 136.0138.0 0.0 C 326 202 5 2 327 ~-282 5 -76 -0.0 -0.2 120.2 0.7-483.7 C Goodnews Ba Capacitor (Wye-Gnd Connected) at Center of Section Goodnews Bay Phase C : Nominal = 0 kvar Actual = 0 kvar ELECTRIC POWER SYSTEMS PAGE 34 OF 44 6/5/2002 West Section Name Feeder Feeder Feeder Atmautluak Kasigluk/Nunapi Capacitor Newtok Generator Chevak Hooper Bay Capacitor Scammon Bay Capacitor DONLIN MINE PROJECT — FEASIBILITY STUDY FOI IO III III III III III IOI IOI ITI TTI SISA Load-Flow Results For West FI III III III II III IOI IO III ITI TOT IIIa oe FOI I tek FI II tok Section Load Load Into Section -- 120V Base -- Losses 3.3-201.1 Phs Cig wow Section Feeder Feeder Feeder Atmautluak Kasigluk/Nu Newtok Chevak Hooper Bay Scammon Bay Phase Dist Nom %V_ Phs Ldg Volt Accm Volt Conduct K FT kVLL Imb Cfg _ kW kvar Amps Pct kW kvar Amps pf Drop Drop Level 138.0 0.0 A 0 0 0 0 120.0 B -876 -82 11 100 120.0 ¢e 0 0 0 0 120.0 Corning 18.0138.0 0.0 B 311 193 5 3 -876 -82 11 100 -0.2 -0.2 120.2 Corning 25.0138.0 0.0 B 1294 -2 16 4 -1188 -111 15 100 0.1 -0.0 120.0 (Wye-Gnd Connected) at Center of Section Kasigluk/Nunapi (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 803 kvar Corning 90.0138.0 0.0 B-5753 153 4 9 -2483 -51 31 100 0.8 0.8 119.2 10MW 80kV Wind Single-Phase CONST. PQ On Phase B At Center of Section Newtok Phase B: 121.3 V 74 Amps 6000 kW 1 kvar Corning 145.0138.0 0.0 B 838 519 13 12 3217 -35 41-100 1.9 2.6 117.4 Corning 170.0138.0 0.0 B 1223 -9 16 5 1227 -202 16 -99 1.0 3.6 116.4 (Wye-Gnd Connected) at Center of Section Hooper Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 767 kvar Corning 170.0138.0 0.0 B 1099 -88 14 4 1102 -290 15 -97 0.8 3.4 116.6 (Wye-Gnd Connected) at Center of Section Scammon Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 769 kvar PAGE 35 OF 44 6/5/2002 ELECTRIC POWER SYSTEMS Southwest Section Name Feeder Feeder Feeder Napakiak Tuntutuliak Kongiganak Kwigillingok Kipnuk Capacitor Generator Chefornak Nightmute Toksook Bay Capacitor Tununak ELECTRIC POWER SYSTEMS DONLIN MINE PROJECT — FEASIBILITY STUDY FOI IIIT III III III III III IIIS IIIT IOI te Load-Flow Results For Southwest FI III III III III IIIT III III III ITI II IOI IT TIT A A Ae Pa tae FORO tk Section Load Ldg Pct Load Into Section -- 120V Base -- Volt Accm Volt pf Drop Drop Level Phs Cfg Dist Nom K FT kVLL &v Imb Phase Conduct kW kvar Amps kW kvar Amps 138.0 0.0 A 0 0 0 0 120.0 B 0 0 0 0 120.0 c -22681 718 30 -95 120.0 Corning 8.0138.0 0.0 C 332 206 5 9-2261 718 30 -95 0.4 0.4 119.6 Corning 48.0138.0 0.0 C 394 244 G | 40) —2617' || 552. | 34 | =98' .L-3) | 17 di1e.3 Corning 73.0138.0 0.0 c 405 251 6 11-3037 454 39 -99° 0.3 2.0 116.0 Corning 83.0138.0 0.0 C 236 145 4. 13-3464 242 44-100 -0.1 1.9 118.1 Corning 118.0138.0 0.0 C-5255 72 9 14 -3710 91 47-100 0.7 2.5 117.5 (Wye-Gnd Connected) at Center of Section Kipnuk (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase C : Nominal = 400 kvar Actual = 392 kvar 10MW 80kV Wind Single-Phase CONST. PQ On Phase C At Center of Section Kipnuk Phase C: 118.9 V 76 Amps 6000 kW -3 kvar Corning 133.0138.0 0.0 Cc 355 220 5 6 1514 75 #19 100 0.4 3.0 117.0 Corning 158.0138.0 0.0 Cc 244 151 4 4 23756 -38 15 -100 0.5 3.5 116.5 Corning 173.0138.0 0.0 Cc 891 -10 8 3 909 16 12 100 0.5 4.0 116.0 (Wye-Gnd Connected) at Center of Section Toksook Bay (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase C : Nominal = 400 kvar Actual = 377 kvar Corning 178.0138.0 0.0 Cc 316 196 5 i 316 151 5 90 0.1 4.1 115.9 PAGE 36 OF 44 6/5/2002 4.1 -40 26.3-145 21.7 -39 5 6 11.1 30.6 -5 Ont YNS ae Oo ono 0.1 -44.8 aagaaaaawp aaa Feeder Napakiak Tuntutuliak Kongiganak Kwigillingo Kipnuk Chefornak Nightmute Toksook Bay Tununak North Section Name Feeder Feeder Feeder Akiachak Capacitor Akiak Capacitor Tuluksak Capacitor Kalskag Capacitor Russian Mission Capacitor Marshall Capacitor Pilot Station Capacitor St Mary's/Pitka Capacitor Mt Village Capacitor Sheldon Point Capacitor Generator ELECTRIC POWER SYSTEMS PAGE 37 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III IIIS IO II IOI III II IOI TOI tr aeekeeEeEH ~Load-Flow Results For North FOI III III III III IOI IOI III III IO IOI IR te Section Load Load Into Section Phase Dist Nom $V Phs Ldg Conduct K FT kVLL Imb Cfg_ kW kvar Amps Pct kW kvar Amps 138.0 0.0 A 3428 -1144 B 0 0 c 0 0 Corning 10.0138.0 0.0 Ay 5367-71 7 13° 3428 -1144 (Wye-Gnd Connected) at Center of Section Akiachak (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 403 kvar Corning 18.0138.0 0.0 A 463 -17 6 11 2881 -1076 (Wye-Gnd Connected) at Center of Section Akiak (Module 1 200 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 300 kvar Actual = 304 kvar Corning 35.0138.0 0.0 A 305 -16 4 9 2412 -1038 (Wye-Gnd Connected) at Center of Section Tuluksak (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 205 kvar Corning 75.0138.0 0.0 A 588 -58 7 8 2097 -940 (Wye-Gnd Connected) at Center of Section Kalskag (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 423 kvar Corning 120.0138.0 0.0 A) 393)--730) 5:1. - 1265) -=307 (Wye-Gnd Connected) at Center of Section Russian Mission (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 213 kvar Corning 145.0138.0 0.0 A 446 «466 6 1 -129 121 (Wye-Gnd Connected) at Center of Section Marshall (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 210 kvar Corning 170.0138.0 0.0 A 698 226 o> 2) =575 306 (Wye-Gnd Connected) at Center of Section Pilot Station (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 207 kvar Corning 180.0138.0 0.0 A 600 168 8 Si 1275) | 317. (Wye-Gnd Connected) at Center of Section St Mary's/Pitka (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 204 kvar Corning 195.0138.0 0.0 A.1104 379 15 97-1877 234 (Wye-Gnd Connected) at Center of Section Mt Village (Module 1 300 kvar/Ph) Phase A: Nominal = 300 kvar Actual = 305 kvar Corning 245.0138.0 0.0 A-5749 §=52 3 11-2986 -43 (Wye-Gnd Connected) at Center of Section Sheldon Point (Module 1 100 kvar/Ph) Phase A: Nominal = 100 kvar Actual = 103 kvar 38 33 28 16 24 37 -65 100 FOI II Rt tke -- 120V Base -- Volt Accm Volt Drop Drop Level 71.0 Glee 0.2 0.8 1.1 0.3 0.3 0.4 120.0 120.0 120.0 120.5 121.0 122.0 123.4 123.1 122.3 121.3 120.9 120.6 120.2 10MW 80kV Wind Single-Phase CONST. PQ On Phase A At Center of Section Sheldon Point Phase A: 121.7 V 74 Amps 6000 kW 0 kvar KW KVAR Cfg Section dist | 229 6.4 -21.0 9.7 -81.6 16.4-261.8 0.7-458.6 0.4-250.6 1.4-237.6 1.6 -84.1 4.9-103.0 39.1-145.7 A Feeder B Feeder C Feeder A Akiachak A Akiak A Tuluksak A Kalskag A Russian Mis A Marshall A Pilot Stati A St Mary's/P A Mt Village A Sheldon Poi DONLIN MINE PROJECT — FEASIBILITY STUDY North Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom sv Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Alakanuk Corning 255.0138.0 0.0 A 726 49 9 10 2724 51 34 100 0.5 0.3119.7 6.7 -36.9 A Alakanuk Capacitor (Wye-Gnd Connected) at Center of Section Alakanuk (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 400 kvar Emmonak Corning 260.0138.0 0.0 A 1255 380 17 7 1991 38 6 25 «100 0.2 0.5 119.5 1.8 -31.7 A Emmonak Capacitor (Wye-Gnd Connected) at Center of Section Emmonak (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 398 kvar Kotlik Corning 300.0138.0 0.0 B&B 732) 7 156 9 3 735 -310 10 -92 0.6 1.2 118.9 2.5-364.3 A Kotlik Capacitor (Wye-Gnd Connected) at Center of Section Kotlik (Module 1 200 kvar/Ph) (Module 2 200 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 399 kvar Aniak Corning 100.0138.0 0.0 A 1224 -91 15 4 1228 -312 .15 -97 0.8 -2.5 122.5 3.9-221.8 A Aniak Capacitor (Wye-Gnd Connected) at Center of Section Aniak (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 849 kvar ELECTRIC POWER SYSTEMS PAGE 38 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY 12 Appendix B-6 : Case 6 - 80 kV SWGR, Donlin Mine, 18 MW Wind Feeders of Bethel Substation East South West Southwest 138 Line TOTAL Feeders of Bethel Substation East South West Southwest 138 Line TOTAL FOI III III III III III III IIIT III IIS IOI IOI III III Ti tee Feeder and Substation Three-Phase Summary FOI IOI IGG JOISTS IIE ISIS IIIA IEE IIIT III II Oe FOI tk FOI I tte kVA pf Amps Cust kW Loss Pct Loss 677 91.1% 2 0 0 0.1% 1695 -99.4% 7 0 12 0.7% 783 -99.5% 3 0 116 14.9% 1081 -100.0% 3 0 48 4.4% 63834 -99.2% 267 0 4640 7.3% 64249 -99.3% 0 4816 7.5% FOI III IOI III IOI III IO III III III III II IO IOI II te Feeder and Substation By-Phase Summary FO IIIS IIIS III ISSO TEI IIIT IIIT tek Teco ee eee FOI I Rt tek -— A/AB —~ | | ——|B/BC)-— || -=(C/CA);~— | | '———— AMPS ——— CUSTOMERS KW LOSSES PCT KVA pf kVA pf kVA PF A B c A B c A B c Loss 0 0.0% 677 91.1% 0 0.0% 0 8 0 0 0 0 0 0 Oo 0.1% 0 0.0% O 0.0% 1695 -99.4% 0 0) |) 21 0 0 0 0 0) | 2) || 0.7% 0 0.0% 783 -99.5% 0 0.0% Oo 10 0 0 0 0 Oo 116 0 14.9% 0 0.0% O 0.0% 1081 -100.0% 0 0) | aa 0 0 0 0 0 48 4.4% 21312 -98.9% 21222 -99.4% 21311 -99.4% 267 266 267 0 0 O 1560 1419 1662 7.3% 21312 -98.9% 21024 -99.6% 21929 -99.3% 0 oO O 1560 1535 1721 7.5% FOI III III IIIS III IIIT III IOI III IIR IO Ie Feeder Mininimum / Maximum Summary ********** FOI U SIGE IIE IOI ITI IIS SISTED IIT IR I ta i FOI te Maximum Section Drop Maximum Loss Pct Minimum Volts Max Conduct. Loading Section Max Section Max Section Min Section Max Feeders of Bethel Substation East A Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 A B Kwethluk 0.4 Kwethluk 100.0 Kwethluk 119.6 Kwethluk 2.4 B c Kwethluk 0.0 Kwethluk 0.0 Kwethluk 120.0 Kwethluk 0.0 C South A Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 A B Napaskiak 0.0 Napaskiak 0.0 Napaskiak 120.0 Napaskiak 0.0 B c Quinhagok 0.2 Eek 51.1 Napaskiak 120.0 Napaskiak 6.1 C West A Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 A B Chevak 1.9 Newtok 46.4 Hooper Bay 118.1 Chevak 11.8 B c Atmautluak 0.0 Atmautluak 0.0 Atmautluak 120.0 Atmautluak 0.0 C Southwest A Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 A B Napakiak 0.0 Napakiak 0.0 Napakiak 120.0 Napakiak 0.0 B c Toksook Bay 0.3 Kipnuk 39.3 Napakiak 120.0 Kipnuk 9.0 C 138 Line A Donlin Mine 2.9 Donlin Mine 13.8 Donlin Mine 116.1 Akiachak 29.7 A B Donlin Mine 2.5 Donlin Mine 12.6 Donlin Mine 116.0 Akiachak 29.6 B c Donlin Mine 2.6 Donlin Mine 13.0 Donlin Mine 114.3 Akiachak 29.7. C ELECTRIC POWER SYSTEMS PAGE 39 OF 44 6/5/2002 DONLIN MINE PROJECT — FEASIBILITY STUDY FOI IOI III ICICI TIGR TOR te sxeeeeee4* Load-Flow Results For East **#*####44 Prrrerrrracereeterreccrvecrssccerrrererrercccrrrery East Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 616 279 8 91 120.0 B Feeder Feeder c 0 0 0 0 120.0 C Feeder Kwethluk Corning 11.0138.0 0.0 B 616 381 3 2 616 279 8 91 0.4 0.4 119.6 0.5-101.8 B Kwethluk FOI III III GIO IOI OIC III TOIT IOI IIIT IO I te *xxeakee** ~~ Load-Flow Results For South ********** FOIE IIIS IIS IO EEEE IG IOOIIIIIIIO I k South Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accm Volt Phs Section Name Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW kvar Amps pf Drop Drop Level KW KVAR Cfg Section Feeder 138.0 0.0 A 0 0 0 0 120.0 A Feeder Feeder B 0 0 0 0 120.0 B Feeder Feeder Cc 1684 -189 21 -99 120.0 C Feeder Napaskiak Corning 6.0138.0 0.0 Cc 414 256 6 6 1684 -189 21 -99 0.0 0.0 120.0 1.5 -44.4 C Napaskiak Eek Corning 46.0138.0 0.0 Cc 293 182 4 5 1269 -401 17. -95 -0.4 -0.3 120.3 5.9-337.0 C Eek Quinhagok Corning 86.0138.0 0.0 Cc 640 396 9 4 970 -246 13. -97 0.2 -0.2 120.2 3.4-360.3 C Quinhagok Goodnews Bay Corning 136.0138.0 0.0 C 326 202 5 2 327-282 5 -76 -0.0 -0.2 120.2 0.7-483.7 C Goodnews Ba ELECTRIC POWER SYSTEMS PAGE 40 OF 44 6/5/2002 West Section Name DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III III III IOI ICICI ITI TI TORT te FO IOI tok Load-Flow Results For West FRR Rk tek FOI III IOI III IOI IOI IO III TI TIO I te -- 120V Base -- Volt Accm Volt Drop Drop Level Section Feeder Feeder Feeder Atmautluak Kasigluk/Nunapi Newtok Capacitor Generator Chevak Hooper Bay Capacitor Scammon Bay Capacitor ELECTRIC POWER SYSTEMS Section Load Load Int Phase Dist Nom $V Phs Ldg Conduct K FT kVLL Imb Cfg kW kvar Amps Pct kW okvar 138.0 0.0 A 0 0 B -779 77 c 0 0 Corning 18.0138.0 0.0 B 309 192 5 3 =779 77 Corning 25.0138.0 0.0 B 1291 800 19 4 -1089 50 Corning 90.0138.0 0.0 B-5746 -474 6 9 -2381 -689 (Wye-Gnd Connected) at Center of Section Newtok (Module 1 300 kvar/Ph) (Module 2 300 kvar/Ph) Phase B : Nominal = 600 kvar Actual = 631 kvar 10MW 80kV Wind Single-Phase CONST. PQ On Phase B At Center Phase B: 123.1 V 73 Amps 6000 kW -0 kvar Corning 145.0138.0 0.0 B 862 534 13. 12 «#3311 =37, Corning 170.0138.0 0.0 B 1259 =9 16 5 1263 -209 (Wye-Gnd Connected) at Center of Section Hooper Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph Phase B : Nominal = 800 kvar Actual = 789 kvar Corning 170.0138.0 0.0 B 1131 -91 14 4 1134 -298 (Wye-Gnd Connected) at Center of Section Scammon Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase B : Nominal = 800 kvar Actual = 791 kvar PAGE 41 OF 44 o Section Amps pf 0 0 10 -100 0 0 10 -100 14 -100 31 96 of Section 41 -100 16 -99 15 -97 8/5/2002 120.0 120.0 120.0 119.9 119.9 121.0 fl roo hor roo orF Newtok 119.1 118.1 eR ow ro woo 0.8 1.7 118.3 1. oO. 53. 52. 4 3: 0-165. 7 -61. 6-178. 4 -63. -3-199. 6-207. or wow Feeder Feeder Feeder Atmautluak Kasigluk/Nu Newtok Chevak Hooper Bay Scammon Bay Southwest Section Name Feeder Feeder Feeder Napakiak Tuntutuliak Capacitor Kongiganak Capacitor Kwigillingok Kipnuk Capacitor Generator Chefornak Capacitor Nightmute Toksook Bay Capacitor Tununak Capacitor Phase Dist Nom %V Phs Ldg Volt Accm Volt Conduct K FT kVLL Imb Cfg _ kW kvar Amps Pct kW kvar Amps’ pf Drop Drop Level 138.0 0.0 A 0 0 0 0 120.0 B 0 0 0 0 120.0 c -1081 25 14 -100 120.0 Corning 8.0138.0 0.0 Cc 334 207 5 4 -1081 25 14 -100 -0.0 -0.0 120.0 Corning 48.0138.0 0.0 Cc 408 253 6 § -1416 -112 18 100 -0.4 -0.4 120.4 (Wye-Gnd Connected) at Center of Section Tuntutuliak Phase C : Nominal = 0 kvar Actual = O kvar Corning 73.0138.0 0.0 C 425 264 6 7 -1831 -38 23 100 -0.4 -0.8 120.8 (Wye-Gnd Connected) at Center of Section Kongiganak Phase C : Nominal = 0 kvar Actual = 0 kvar Corning 83.0138.0 0.0 C 248 153 4 98-2263 -124 26 100 -0.3)-1.1 121.1 Corning 118.0138.0 0.0 C-4201 495 a 9 =2515 =218 31 100 -0.4 -1.6 121.6 (Wye-Gnd Connected) at Center of Section Kipnuk Phase C : Nominal = 0 kvar Actual = O kvar 10MW 80kV Wind Single-Phase CONST. PQ On Phase C At Center of Section Kipnuk Phase C: 122.0 V 62 Amps 5000 kW 0 kvar Corning 133.0138.0 0.0 Cc 385 32 5 6 1667 -532 22-95 -0.3 =1.8 121:8 (Wye-Gnd Connected) at Center of Section Chefornak (Module 1 100 kvar/Ph) (Module 2 100 kvar/Ph) Phase C : Nominal = 200 kvar Actual = 206 kvar Corning 158.0138.0 0.0 C 269 166 4 § 1279 -449 17 -94 -0.5 -2.3°122.3 Corning 173.0138.0 0.0 C 655 -428 10 4 1006 -398 13 -93 0.3 -2.0 122.0 (Wye-Gnd Connected) at Center of Section Toksook Bay (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase C : Nominal = 800 kvar Actual = 834 kvar Corning 178.0138.0 0.0 C 350,217 5) |) 1) 350:) 467 § ~90 0.1 -1.9 121.9 (Wye-Gnd Connected) at Center of Section Tununak Phase C : Nominal = 0 kvar Actual = 0 kvar PAGE 42 OF 44 6/5/2002 ELECTRIC POWER SYSTEMS DONLIN MINE PROJECT — FEASIBILITY STUDY FIO III III III III II TOI III III III III IOI III I IK tekeeeeee* ~Load-Flow Results For Southwest FIO II III ITI III IOI IOI III III IIIT ITI OIA Ie So tie Section Load Load Into Section -- 120V Base -- 3-8-115.5 rw Re en wre an on 0.1 -49.4 Section Feeder Feeder Feeder Napakiak Tuntutuliak aqaaqawp a Kongiganak c Kwigillingo Kipnuk Chefornak c Nightmute Toksook Bay € Tununak 138 Line Section Name Feeder Feeder Feeder Akiachak Akiachak Akiachak Capacitor Akiak Akiak Akiak Tuluksak Tuluksak Tuluksak Capacitor Kalskag Kalskag Kalskag Capacitor Russian Mission Capacitor Marshall Pilot Station Capacitor St Mary's/Pitka Mt Village Capacitor DONLIN MINE PROJECT — FEASIBILITY STUDY FOI III II III III III III I III IIIT IOI IT tte Load-Flow Results For 138 Line FOI III III III III III III III IOI IIIT ISI III IOI tt te TIO tot OO kt 89.9 98.8 104.5 71.4 71.2 87.4 149.8 165.6 136.5 46.9 193.5 149.1 76.1 40.8 73.1 350.4 347.6 317.2 428.7 90.8 285.0 2.7-426.0 0.0-248.9 1.7-=239.7 awrawp awp oP A A Feeder Feeder Feeder Akiachak Akiachak Akiachak Akiak Akiak Akiak Tuluksak Tuluksak Tuluksak Kalskag Kalskag Kalskag Russian Mis Marshall Pilot Stati St Mary's/P Mt Village Section Load Load Into Section -- 120V Base -- Phase Dist Nom $V Phs Ldg Volt Accm Volt Conduct K FT kVLL Imb Cfg _ kW kvar Amps Pct kW kvar Amps pf Drop Drop Level 138.0 0.0 A 21078 -3149 267 -99 120.0 B 21096 -2315 266 -99 120.0 c 21180 -2351 267 -99 120.0 795 ACSR 52.8138.0 0.1 A 0 0 0 30 21078 -3149 267 -99 0.1 0.1 119.9 B 529 328 8 30 21096 -2315 266 -99 0.3 0.3 119.7 c 0 0 0 30 21180 -2351 267 -99 0.3 0.3 119.7 (Wye-Gnd Connected) at Center of Section Akiachak Phase A: Nominal = 0 kvar Actual = 0 kvar Phase B : Nominal = 0 kvar Actual = 0 kvar Phase C : Nominal = 0 kvar Actual = 0 kvar 795 ACSR 95.0138.0 0.2 A 0 0 0 30 20988 -3240 267 -99 0.1 0.1 119.9 B 452 280 7 29 20468 -2719 260 -99 0.1 0.4 119.6 c 0 0 0 30 21076 -2446 267 -99 0.2 0.5 119.5 795 ACSR184.8138.0 0.4 A 0 -199 3 30 20917 -3317 266 -99 0.1 0.2 119.8 B 0 -199 3 28 19945 -3040 254 -99 0.2 0.6 119.4 ic 290) -215 4 30 20989 -2519 266 -99 0.6 1.1 118.9 (Wye-Gnd Connected) at Center of Section Tuluksak (Module 1 200 kvar/Ph) Phase A: Nominal = 200 kvar Actual = 199 kvar Phase B : Nominal = 200 kvar Actual = 199 kvar Phase C : Nominal = 400 kvar Actual = 395 kvar 795 ACSR396.0138.0 0.9 A 551 -5S6 7 29 20767 -3283 264 -99 0.3 0.5 119.5 B 0 -396 5 28 19808 -2888 252 -99 0.5 1.0 119.0 c 0 -389 $ 29 20505 -2453 262 -99 1.2 2.3 117.7 (Wye-Gnd Connected) at Center of Section Kalskag (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 398 kvar Phase B : Nominal = 400 kvar Actual = 396 kvar Phase C : Nominal = 400 kvar Actual = 389 kvar Corning 441.0138.0 0.0 A 384 -276 6 4 284 -1004 aS) (20-262 —2o Zl (Wye-Gnd Connected) at Center of Section Russian Mission Phase A: Nominal = 500 kvar Actual = 514 kvar Corning 466.0138.0 0.0 A 444 276 6 @ -103 ~302 4 32 -0.4 -2.1 122.1 Corning 491.0138.0 0.0 A 704-398 10 2 -547 -329 8 86 0.4 -1.8 121.8 (Wye-Gnd Connected) at Center of Section Pilot Station (Module 1 400 kvar/Ph) (Module 2 400 kvar/Ph) Phase A: Nominal = 800 kvar Actual = 835 kvar Corning 501.0138.0 0.0 A 607 376 9 | 5 =1253 309 16 -97 0.2 -1.6 121.6 Corning 516.0138.0 0.0 Allly 75 14 7 -1861 19 23-100 0.2 -1.3 121.3 (Wye-Gnd Connected) at Center of Section Mt Village (Module 1 300 kvar/Ph) (Module 2 300 kvar/Ph) Phase A: Nominal = 600 kvar Actual = 617 kvar PAGE 43 OF 44 6/5/2002 ELECTRIC POWER SYSTEMS DONLIN MINE PROJECT — FEASIBILITY STUDY 138 Line Section Load Load Into Section -- 120V Base -- Losses Phase Dist Nom $V Phs Ldg Volt Accom volt Phs Section Name Conduct K FT kVLL Imb Cfg_ kW kvar Amps Pct kW kvar Amps pf DrOP Drop Level KW KVAR Cfg Section Sheldon Point Corning 566.0138.0 0.0 A-5748 47 a | a, 2963 49 37-100 0-9 -9-5 120.5 39.3-150.9 A Sheldon Poi Capacitor (Wye-Gnd Connected) at Center of Section Sheldon Point (Module 1 100 kvar/Ph) Phase A: Nominal = 100 kvar Actual = 104 kvar Generator 10MW 80kV Wind Single-Phase CONST. PQ On Phase A At Center of Section sheldon Point Phase A: 122.2 V 74 Amps 6000 kW 5 kvar Alakanuk Corning 576.0138.0 0.0 A 728 49 9 10 2726 153 34 100 0-6 0.2 119.8 6.7 -36.1 A Alakanuk Capacitor (Wye-Gnd Connected) at Center of Section Alakanuk (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 402 kvar Emmonak Corning 581.0138.0 0.0 A1257 381 17 7 1991 140 25 100 0-3 0-5 119.5 1.4 -30.4 A Emmonak Capacitor (Wye-Gnd Connected) at Center of Section Emmonak (Module 1 400 kvar/Ph) Phase A: Nominal = 400 kvar Actual = 398 kvar Kotlik Corning 621.0138.0 0.0 A 731 154 9 3 733 -210 10 -96 0-8 1.2 118.8 2.5-363.9 A Kotlik Capacitor (Wye-Gnd Connected) at Center of Section Kotlik (Module 1 300 kvar/Ph) Phase A: Nominal = 300 kvar Actual = 299 kvar Aniak 795 ACSR528.0138.0 1.2 A 0 -495 6 28 19582 -2570 249 -99 0-4 0-9 119.1 195.7 76.5 A Aniak Aniak B 0 -490 6 28 19491 -2583 249 -99 0-5 1-5 118.5 209.8 53.5 B Aniak Aniak C-1113 -363 15 29 20077 -2348 259 -99 0-8 3-1 116.9 244.4 177.3 C Aniak Capacitor (Wye-Gnd Connected) at Center of Section Aniak (Module 1 500 kvar/Ph) Phase A: Nominal = 500 kvar Actual = 495 kvar Phase B : Nominal = 500 kvar Actual = 490 kvar Phase C : Nominal = 1100 kvar Actual = 1053 kvar Donlin Mine 795 ACSR924.0138.0 1.0 18743-2342 242 27 19386 -2151 247 -99 2-9 3.9 116.1 642.4 190.4 A Donlin Mine Donlin Mine B18696-2327 242 27 19281 -2146 247 -99 2-5 4.0 116.0 585.3 181.0 B Donlin Mine Donlin Mine 18116-2259 238 27 18719 -2162 243 -99 2.6 5.7 114.3 603.3 96.4 C Donlin Mine Capacitor (Wye-Gnd Connected) at Center of Section Donlin Mine (Module 1 1000 kvar/Ph) (Module 2 1000 kvar/Ph) (Module 3 400 kvar/Ph) Phase A: Nominal = 2400 kvar Actual = 2342 kvar Phase B : Nominal = 2400 kvar Actual = 2327 kvar Phase C : Nominal = 2400 kvar Actual = 2259 kvar ELECTRIC POWER SYSTEMS PAGE 44 OF 44 6/5/2002 A.2. Prospecting For Low Resistance Electrical Grounds in Permafrost Regions PROSPECTING FOR LOW RESISTANCE ELECTRICAL GROUNDS IN PERMAFROST REGIONS BY FRANK BETTINE 26 NOVEMBER 1979 PROSPECTING FOR LOW RESISTANCE ELECTRICAL GROUNDS IN PERMAFROST REGIONS Abstract In permafrost regions where the resistivity of the soil is extremely high, it is often times necessary to provide a low rapes tense electrical earth connection. This paper examines the basic concepts involved and two commercially available instruments which are useful in locating unfrozen, low resistivity soils capable of providing the low resistance earth connection. Discussion It is not possible using conventional earthing electrode sys- tems embedded directly in permafrost soils to obtain the required low resistance earth connection. This is because permafrost (1) soil resistivities may average in excess of 1000 ohm-meters. Table 1 illustrates the effect of temperature on soil resistivity. It is believed that an effective earth connection to the permafrost can be obtained by locating sufficiently large thaw bulbs, unfrozen zones or aquifiers within the permafrost, constructing a convention- al earth electrode system within this unfrozen area, and then use the surface area of the unfrozen ground to provide the necessary (1) The resistance of a cube of material with the cube sides being one meter in length. TABLE 1 EFFECTS OF TEMPERATURE ON EARTH RESISTIVITY Temperature °C Resistivity, Ohm-cm 20 7,200 10 - 9,900 O(water) 13,800 O(ice) 30,000 -5 79 ,000 -15 330,000 Sandy loam 15.2% moisture. surface contact area to the permafrost to insure a low resistance connection. / The problem now exists in determining the amount of surface area required at the unfrozen ground - permafrost interface to provide the low resistance connection. For simplicity a hemispherical surface area will be assumed. The resistance R, in ohms of a hemi- shpere buried in the surface of the earth is: R =P/27r . (1) MW where: P = soil resistivity in ohm-meters r = radius of hemisphere solving for the radius r, we obtain xr = f/2R (2) The surface area can then be found by substitution of r into the equation for determining the surface area of a hemishpere. This results in the following equation. A = (P/RT/27 (3) where: A = surface area in square meters and R as previously defined Table 2 illustrates the required radius r and surface area A, for specific values of desired resistance in 1000 ohm-meter soil. Note that the surface area required to obtain one ohm of resistance is) 100 times that required for 10 ohms and twenty five times that required for 5 ohms of resistance. Although these calculations were accomplished using a hemisphere, it can be assumed that any geometric shape that provides the required surface contact area will provide approximately the same overall resistance to the permafrost. Table 2 (1000 ohm-meter soil) Resistance Value radius Surface area Desired in ohms meters sq. meters 1 160 160,000 5 32 6,400 100 16 1,600 The problem now becomes one of locating and mapping these unfrozen areas using proper prospecting techniques, coupled with available instrumentation. Two such instruments which are commercially avail- able and which provide statisfactory results under a variety of conditions are the Geonics Limited EM31 and the Biddle Earth Tester. The advantages, limitations and techniques for use of each of these instruments is discussed below. Geonics EM31 (See Figure 1) The EM31 is a portable self contained instrument used to measure the electrical Counueivlie Re the earth without physical contact. The EM31 uses a magnetic dipole transmitter to induce weak elec- tric currents in the earth. These weak currents produce a secondary magnetic field which is linearly related to the earth conductivity. The EM31 compares the weak secondary magnetic field with the primary field to produce a direct continuous readout of the terrain conductivity. (1) conductivity is the reciprocal of resistivity Figure 1 The EM31 has been used successfully for: (1) detecting and delineating the boundries of gravel deposits (2) detecting and delineating regions of high ice content in shallow permafrost. (3) determining the thickness of the active layer i.e. the depth to permafrost (4) locating buried river valleys infilled with glacial till. (5) delineating conductive regions due to ground water pollution. (6) determining the depth to bedrock through muskeg. The EM31 will yield useful information only in those situations where the anomaly to be studied presents a significant and unambiguous con- ductivity contrast with the surrounding medium. Figure 2 illustrates the ability of the EM31 to delineate the active channels of the Skaviovik River, located on the North Slope. The major advantage of the EM31 is the speed at which a survey can be conducted. Using the EM31 it is possible to determine the magnitudes of the soil conductivity by simply walking over the area in question while monitoring the instrument. The disadvantages of the EM31 are it's inability to accurately read through highly conductive layers and it's fixed depth of penetration. Biddle Earth Tester The Biddle Earth Tester is a self contained portable instrument which makes use of the four point Wenner method for measuring soil resis- tivity. This method requires physical contact with the earth through probes as shown in Figure 3. Four electrodes ( 2 current and 2 inter- - SHAVIOVIK RIVER (COAST) 147°15*W 70° 6°N 11-20-76 10 - WEST-BANK , cit 7 ee % - 7 Rae am ome Oley, tii CHANNEL ie < a a” ee 100 HANN CHANNEL EM 31 EM 31 RELATIVE RESISTIvITy RESPONSE 0.1 GOO 5 10 200 300 100 DISTANCE (m) Figure 2 mediate potential electrodes) are placed in the earth at equal distances ina straight line. A typical set-up is shown in Figure 4, When using a Biddle Earth Tester to measure the soil resistivity. The value obtaine from the instrument will be resistance in ohms. It is then possible to calculate the resistivity of the soil by applying the formula, fP = 27~AR (4) where: A = distance between electrodes in meters P R resistivity of soil to depth A = measured resistance in ohms A major disadantage of the Wenner method is it's slowness. Probes must be repeatedly moved when resistivity surveying a line or area. A method for accomplishing this is shown in Figure 5. Another dis- advantage of this method is that it is not possible to read the soil resistivity directly from the instrument. Equation (4) must be solved for each reading to obtain the resistivity. The major advantage of the Wenner method is it's ability to more precisely determine the resistivity of layered soils. Recall that in equation (4), A is the spacing between electodes and that the formula gives the theoretical resistivity of the soil to depth A. By varying the spacing A it is therefore possible using the Wenner configuration to measure the soil resistivity to any desired depth. The Wenner method like the EM31 is not capable of accurately reading thorough a highly conductive top layer. Nor can this method be used in high resistivity soils where the resistance between the current electrodes is so great as to prevent the flow of reasonable currents. Current Electrodes I I A potangral xO Electrodes. 4 \ Figure 3 The Four Terminal Connection small size electrode A> 20b Figure 4 Earth Tester Connection 10 Figure 5 Prospecting for Best Earth Electrode Location Drive four electrodes at a distance A apart, no more than 6 in. deep, along the line a-b-c-d. Measure the resistance R between electrodes b and c. Shift the electrodes along the line in question to points b-c-d-e, c-d-e-f and so on until the entire line has been covered. Repeat the process until the entire area has been covered. at Armed with the above information it should be obvious that it is possible to use both instruments to advantage in the field. The EM31 can be used to quickly locate and delineate the boundary of unfrozen ground. Once this is accomplished, the Biddle Earth Tester can be employed to accurately map the depth of the unfrozen soil and/or the layers contained therein. The information obtained can then be used to calculate the surface area of the unfrozen soil that is in contact with this permafrost. In addition, this information can be used to design a conventional earth electrode system which will be embedded in the unfrozen soil. One obvious location to search for thawed ground is beneath lakes or rivers which do not freeze solid during the winter. The EM31 can be used for prospecting frozen lakes and rivers to quickly locate the boundaries of the unfrozen waters beneath, The EM31 is not capable of seeing through water, so another means for determining the depth of unfrozen soil beneath the lake or river must be provided. This can be accomplished by using influence value charts for temperature distribution from heated structures on permafrost. See Figure 6. For example, suppose it is desired to find the required diameter of an unfrozen round lake which would provide a thaw bulb of sufficient extent to obtain a maximum of 5 ohms contact resistance to the perma- frost. The depth of thaw under the lake could be assumed approximately equal to the radius in meters listed in Table 2 for five ohms resis- tance or approximately 32 meters. Assuming a permafrost temperature of 30 degrees F and a lake bottom temperature of 38 degrees F, the diameter of unfrozen lake bottom required would be approximately fifty meters. Estimates on the depth of thaw for rivers and various shaped lakes can readily be estimated using similar influence charts. WFLUENCE VALUE 12 Permafrost 289 FIG. 20-7 Influence value chart for temperature distribution from heated structure on permafrost. A/B = 1.00. 13 Conclusion This paper has briefly examined two types of instruments used in prospecting for unfrozen soils in permafrost areas. In addition, methods were presented for calculating the depth of thaw under rivers and lakes and for determining the required surface area of the unfrozen soil in contact with the permafrost for any specified value of resistance. References EM 31 Operations Manual, Geonics Limited, Ontario, Canada. Geophysical Survey of the Arctic Coastal Plain, Dora L. Gropp, July, 1977. The Earth Connection (A Study of Earth Electrode Systems), Masters Thesis, University of Oklahoma, Frank J. Bettine, 1978. TAL_. a isfo Lo: 1Bu bjec Cav : ee nlidied - Wy Of. SE , to sion 3-121 —_——- TABLE 7, Equations for Heat Loss from Buried Objects and Cavities (Continued) 7 : ' ' Infinite circular hole in semi-infinite solid “A X a/k(ty- 1.) © 2e/cosh™! (2x/D) . \ ; 7 A D #2e/ In [2x0 + Jl@x/0=1] : INK WS * 2m/ In (4x/0) Two infinite circular holes in semi-infinite solid a Ax\ (4x) Jig [ltxg)? + x (Gin (2). (ar ‘ i x d S ] ai/k(t-t.) #20 ia Taka. eee « : SS fo = t,) x, +X9)* + a/kalt,=t) = #/ In (4a/b) SI In G4 - a In fost . x20 an 7 eu an __ (interchange subscripts for a3) 22n/ In APR = ty) © 2n/ In[’2V/e DI sinh(2wx/U)} {Any one hole) N a7aUh-t) # 2H/ tn [(2U/eO) sin (w8/ UI] % oie + (Any one hole) [4 a et Spherical hole in semi-infinite solid Q/kO(t, = t,) © 2n/(1- 04x) 820 d/| In (8074) © 2w/ In (80/d) a/rOlt,=1) * aril fe) In (20/x) , Q/KLIt, ~ 1.) = 207 In (4x/0) ® 2n/ In (2L/0) INFLUENCE VALUE T/ Teongs FIG. 20-7 permafrost. at a ,, 5 SS Aa TD A&iX@o@Q@q WA SN S CUES SN sot WA BESSON [| velo TS WEEEEBSSSSS “we +B *0001025)500 el< pix ol to 1s 20 25 30 35 40 45 = 50 RELATIVE DEPTH 35 2/8 Influence value chart for temperature distribution from heated structure on A/B = 1.00. 290 Special Topics 1 1000 eee Nee aa 28 0800 i 0.700 HEATED BULOING ” 0600 yp 283. 8 8 My, ee S| WARIS USS Sh 0500 5 - eos WY] OX | ee Wii necTanaut 0060 ; SNAG $1.50 is SNL sie 0040 SNC {-c00128500 0035 | v3 25 SNS SN i SNA 002 / SSS SN ES Ky ri Nl WML Y ae | — a > AMIE ° os 10 8 200 «28 30 33° 40048 50 $5) 60 t RELATIVE OCPTH 2/8 SAMA EZ WA ae EPS || | FIG. 20-8 Influence value chart for temperature distribution from heated structure on permafrost, A/B = 1.50, Ss eT Sees nS EE + om Permafrost NE I LR ae = BNE ene oe HYPE ESN VRC AEN HARE SN VASE SSAC eS WHAT MALL LL ELE Octo, ALD ILWITRO TIM STATUS Me Leeaa 2 RELATIVE CtPTH 270 FIG. 20-9 Influence value chart for temperature distribution from h structure on permafrost. A/B = 2.00. ' Permafrost Special Topics 292 oe Za SSS : S eeaeesumel ss RELATIVE CEPTH 2/8 < ° 5s $ 38 ° oy aR ES KN RISES hy RS ° CIKAIRSESESSSSSS: 20 25) =~ 3 FIG, 20-12 Influence value chart for temperature distribution from he: structure on permafrost. A/B = yg. 2.5 | | | structure 60 5 Wo iin a V/A Ay V1 EI ee iT | \ Han \ o 655 78 6 RELATIVE OEPTH fee AAC 35 FIG. 20-1 Influence value chart for temperature distribution from heated on permafrost. A/B = 23, ‘3. co ‘const INFLUENCE WALUE = T/T, 294 Special Topics Ye Y7_| | N | si = LN = NAN A Sw SAAN \ : ll a RECTANOLE : +400 R § f-000 iat MW WW _ §+00010.29)500 . | | tt W Pt A | ANN Ei EES 0010 18 ° 95 10 % 20 25 yo 35 40 45° $0 55) «60 ACLATIVE DEPTH 2/8 FIG, 20-12 Influence value chart for temperature distribution from heated structure on permafrost, A/3 = 4,00, Permafrost —— PY NV LL a WTA WU II] y Pt Mi Pt EI ; NA Evatiop N recent SS fos00 Pe RS F000 te }ro0on2: eh PT NAA | TT IA | | | th Pt EE PE | uv o 05 10 15 20 25 30 33 40 45 $0 $5 60 7 RELATIVE DEPTH 278 FIG, 20-13 Influence value chart for temperature distribution from heu ture on permafrost. A/B = $.00, 296 Special Topics | Permafrost 1.000 0800 | 0300 | —] © o800 0700 $ pace r\ \ 0600 y. 3 0600 t 0500 ie 3 w 0.500 0.409 u ; 0.450 400 0350 i : : sso N | | | PSS | TT TIN ew aaa | | N 0250 | + x eZee 0.200 LA 2 r Ne GE 0150 {eee staP est SNe | 0100 WAKA ee SSS oso : oto TAZ i a a SS 0080 UV A S SS ‘00 09 0080 t i ——— 000(025)5 site | 0070 eas == o C060 1 entree al “ACEP oe MMV ZAZA SSS Sess 0040 saa VL py | J | fT 003s H| 0033 Lf) en | P| {| {| [ Jf f 0.100 ° os 10 's 20 25) «(30 35° 40 «645050 ss) 6o a7 . . ° os 19 18 20 25 30 35 40 43 $0 S35 60 m9 RELATIVE OCEPTH 2/8 RELATIVE CEPTH 270 FIG. 20-14 Influence value chart for temperature distribution from heated struc- oy FIG, 20-15 Influence value chart for temperature distribution from heute ‘ure on permafrost. A/B = 10.00. ture on permafrost. A/B = 1,000.00. 298 Special Topics THREE DIMENSIONAL TE MPERETURE = 0800 DISTRIBUTION INFLUENCE VALUES ; - Tens) ALONG VERTICAL CENTERLINE > : OF RECTANGLES FROW HEATED STRUCTURES ON PERMAFROST #000 INFLUENCE VALUE, eves ance echnecnsamat rinianasis aanettanaltnbseitpatainnlaliepabaaentoatrers as so ss RELATIVE DEPTH, 2/8 FIG. 20-16 Influence value chart for temperature distribution from heated structures on permafrost along vertical centerline of rectangles. Pressure of water vapor, Ibf/in.? FIG. B-13a Psychrometric chart (for 1 alm pressure). Courtesy of the General Electric Company. Barometric pressure, 14.696 lbf/in.* (1 lbm = 7000 grains) 30 Bavamelic presse, 14596 Ib/sq In. _ A Y VW LN | 60 X A 180 0 10 3 140 i 40 120 ; a » 20 100 $ cS 80 5 . Ss a: AES Roce A 10 Eee AAG A’ 20 = ; sy AAR PAW 0 60 70 80 90 100 110 120 ° * Dry-bulb temperature, °F Relate co (Aressuve WW, Oin Gare ee “ diy Sat: Vw Pressure tats Tangy - 2? datm = (47 psé : 760 mo Hy = (013 mbaAe 72h ar iw lly > 324 ftunte A.3. Optical Phase Ground Wire Information CORNING STARWay OPGW DOUBLE LAYER DESIGN (DABB) APPLICATION Optical Groundwires to be installed along overhead power lines. FEATURES & BENEFITS & Central tube design provides optimum protection of fibers against mechanical stresses and lightning ® Minimized additional loads due to small outer diameter and low weight @ High fiber counts up to 96 and variance in fiber count for the same cable type § Fiber bundles (12 each) for more than 12 fibers PROPERTIES No. of armoring layers: 2 Armoring material: Al-alloy (AA) and Al-clad steel (ACS) Storage temperature: -40 °C to +80°C Installation temperature: +10 °C to +50 °C Operation temperature: -40 °C to +80 °C * other options on request eth feo) B Ch) Standard attenuation values* for the fibers: 0.36 dB/km @ 1310nm + 0.22 dB/km @ 1550 nm Standard fiber counts* are 12/24/36/48/60/72/84/96 > » en arama Corning Cable Systems + P.O. Box 70 03 09 + 81303 Munich + Germany » www.corning.com/cablesystems/europe TECHNICAL DATA 1D160-103/5-xxxEg D160-092/44-10KEQ D160-098/29-xxxE9 Di80-108/20-x0xEQ Di80-088/59-xxxEQ D180-107/29-100KE9 D1B0-099/49-xxxEQ D200-121/15-xxEQ D220-124/25-xxxEQ D240-118/29-200xE9 D260-127/42-xxxEg 0320-148/21-0xE9 D380-154/51-xxxEg 1.460-180/26-100E9 PUT agers Se Ys) (lat)Tinit = 4a°g =<" ; ¥ Ohm/km Lo SSRESEEEKSERRREER 4 RRC EU Pe sot maa ala a tye SSSSLSVESSUSLATEY BSVOBH Sees eeyse BUT ee rl g Coefficient Cross Section aL a QRDER INFORMATION ld Ors e Ries) Beers Pa) D220-124/25-xxxEg 'D240-118/29-00EQ D260-127/42-xxxEg D320-148/21-20xEg 0380-154/51-xxxEQ 10460-180/26-20xE9 REEL SIZES AND Max. DELIVERY LENGTHS Reel Size (mm) and max. Cable Delivery Length (m) Type Code ? [ees ae mest 9 eis UTI |) eae fee us 12,24 12, 24, 36, 48 12,24 12,24 12,24 12, 24, 36, 48 12, 24, 36, 48 48, 60, 72, 84,96 12,24 12, 24, 36, 48 12,24 12, 24, 36, 48 48, 60, 72, 84,96 12, 24, 36,48 12, 24, 36,48 12, 24, 36, 48, 60 12, 24, 36, 48, 60 enol Bae 5 ere, cer} rr ai 4 Di20-074/44-10xEQ 5-400 / D140-079/49-xxxEQ 3.300 4-800 5-600 6.900 Di40-088/29-100E9 3-700 5-400 6.000 -/ 1D160-103/15-x00xEQ 3-700 5-400 6.000 - D160-092/44-10xE9 3-300 4-800 5.600 6.000 Di60-098/29-xxxEg 3.300 4-800 5.600 6.000 D180-108/20-00E9 3-300 4800 5.600 6.000 ' D180-088/59-xxxEg - 4.300 5.100 6.000 D1B0-107/29-100E9 3.300 4.800 5.600 6.008 Di80-099/49-xxxEQ - 4-300 5.100 6.000 D200-121/15-10xE9 3.300 4-800 5.600 6.000, D220-124/25-10xE9 - 4-300 5.100 6.000 D240-118/29-xxxEQ - 4-300 5.100 6.000 1D260-127/42-xxxEQ - 3.800 4.400 6.000 10320-148/210aE9 - 3-800 4400 6.000 D380-154/51-xxxEg - - 3.500 6.000 1D460-180/26-10xEg : : 3.500 6.000 * other options on request rote No. C1 B39 -1 -7600/ CCS 0201x Corning Cable Systems « P.O. Box 70 03 09 * 81303 Munich » Germany + www.corning.com/cablesystems/europe All rights reserved. Thus publication mus! mot be reproduced or copied in any way whatsoever without the express consent in wnting of Corning Cable Systems Geb & Co.KG Subject to avadlabulty and technical moddications. Corming Cable Systems GmbH & Co. KC reserves the right to improve, enhance or otherwise modify Corning Cable Systems products without prior notification. including and in particula’ technical data and other information about such products. There 1s no legal obhgation to supply a specific product to a precise specification until a binding order ws accepted by Corning Cable Systems GmbH be Co. KG Printed in Germany COPYRIGHT ©2001 © Copyright 2002 ALL RIGHTS RESERVED Alcatel 6840 - 6844 Power Lines Optical Aerial Solutions for Energy Networks OPGW, OPPC, MASS, ADSS and ADL Fiber optic cable links are the foundation Regional and intemational power trans- of such communications systems, since they mission lines require modern network automation and remote control systems. provide high capacity transmission over To accomplish this, power utilities started long distances. At the same time they are very early to equip their lines with reliable not influenced by ic fields telecommunications connections. Telecom- and do not exhibit any cross-talk, which munications deregulation now opens up ore ii t consideration for installation the opportunity for power utilities to lease on high voltage (HY) lines. dark fibers or transmission capacity, or to become telecom operators themselves. easel eRe AI mc elumelt melita The easiest way to connect power plants and control stations is with existing high-voltage lines. The most common method is to install Wire (OPGW), which contains optical fibers housed in stainless steel tubes, as a substitute for existing ground wire. Another possibility consists of OPPC . incorporating opti for 30 kv fervencsrere ADL on phase ais rd conductor phase conductors. This solution is called an Optical Phase Conductor (OPPC). Beside these integrated solutions, additional cables Various options are available to install optical cables on power lines can be installed on transmission towers. While these self-supporting cables a ground wire or a phase conductor Self-supporting cables for installation are hung between the towers, may serve as the messenger. The on high-voltage lines are either Metallic All-Dielectric Lashed (ADU is a diagram on the next page summarizes Aerial Self-Supporting (MASS) or All-Dielectric Self Supporting (ADSS). Rev 0, Jan. 02 small-sized cable which is attached to a messenger wire. In HV lines, either v ALCATEL ARCHITECTS OF AN INTERNET WORLD and categorizes these solutions. SR Apc © Copyright 2002 ALL RIGHTS RESERVED Alcatel 6840 - 6844 Power Lines Pac steel tube designs Rev 0, Jan. 02 The optimal solution for each project demands a careful evaluation of many parameters such as the maximum load for towers, possible wind and ice loads, etc. 6841 OPGW - Optical Ground Wire The substitution of an existing ground re by a cable combining o classical Gee of an earth wire and telecomm- unications capacity has a long history. Today, OPGW is the most important and accepted technology to equip high- voltage lines with transmission capability. An OPGW has to two functions. On one hand, it must function as an earthing conductor, i.e., conduct short- circuit currents that result from faults in the electrical system to earth, and safeguard the line from lightning. On the other hand, it must protect the optical fibers from external forces and harsh environmental conditions, such as extreme temperatures, wind and ice loads. By combining these functions in one cable, OPGW considerably reduces loads on the towers. The challenge is to optimize the mechanical, electrical, and data transmission properties to fulfill all overhead line design requirements. v ALCATEL ARCHITECTS OF AN INTERNET WORLD The main characteristics of an OPGW are: © high mechanical strength, which is muinly determined by the amount of steel used © short-circuit current , which is mainly determi ped Become of aluminum (alloy) © the number of optical fibers. Alcatel has chosen the steel tube design for OPGW. In this design, the optical fibers are protected by stainless stee! tubes which ‘one or more of the armoring wires of a bare ground wire, thus forming a completely metallic solution. More than twenty years of experience in optical ground wire technology and excellent quality have made Alcatel one of the biggest suppliers of OPGW in the world. Alcatel 6840 - 6844 Power Lines a irre ts er area Pr ei ee A\ll-Dielectric lashed cable (ADL) is not a self-supporting construction, but needs to be attached to a messenger wire. The could be a ground wire in high-voltage lines or @ phase conductor in low and medium-voltage lines. The cable is fixed by two lashing binders made of coated aramid yarn which are helically wound around the messenger wire and the ADL cable. This process is carried out using a small machine - called a *losher* - For additional information visit Alcatel online or call your nearest Optical Fiber Sales Representative www.aicatel.com/opncaitiber Brazil +55 11 3068 9993 France +33 155515151 France (HQ) +33 13919 1200 Germany +49 2166 27 2667 India +91 11 335 9650 Spain +34 942 247 111 UK +44 1633 413 600 North America +1 828 459 9787 800 879 9862 Rev 0, Jan. 02 © Copyright 2002 ALL RIGHTS RESERVED 6842 ADL - All-Dielectric Lashed Cables travelling along the messenger wire. It can be either pulled by hand or by a tug. The cable can be fed into the lasher either from the ground, or it can be carried by a special drum carrier on the messenger. With these different components and user options, the technology is very flexible and can be adapted to specific conditions. ADL technology makes fast and cost-effective installation of optical fiber cables possible on HV lines. ADI cable, lasher and the messenger wires PCr Ue In addition to optical cables, products management, training and follow-up such as joint boxes and accessories services for all products and systems. are a er for the implementation of Alcatel can also provide preliminary optical links on power lines. Alcatel or feasibility studies, as well as supply offers installation supervision and guidelines, engineering, project Power Line Solutions Benefits OPGW solutions which are reliable and long-lasting Fast and low-cost ADSS and ADL networks Ideal for replacing or reinforcing existing networks Easy access for all splices and repairs Weather-proof and environmentally friendly turnkey telecommunications systems. Installation supervision and training available Turnkey solutions for operators who want rapid implementation v ALCATEL ARCHITECTS OF AN INTERNET WORLD Be ecm emer ae Se ited pepe een bed ten ma eee © Copyright 2002 ALL RIGHTS RESERVED. Sometimes, medium-voltage lines and high-voltage lines up to 150 kV are not equipped with a ground wire. Consequently, replacement a an OPGW is not feasible. To equi a transmission line with oplieal Fibers, an Optical Phase Conductor (OPPC) may be used. Here again, the optical cable has to provide two different functions. It must carry the permanent current in the three-phase system, and it has to house and protect the optical fibers. To keep the electrical system running well, the Where the substitution of a ground wire or phase conductor is either impossible ‘or uneconomical, additional cables can be installed on towers. The only function that these cables have is to house and protect the optical fibers. A universal solution for all voltage levels is the Metallic Aerial Self-Supporting (MASS) Rev 0, Jan. 02 Alcatel 6840-6844 Power Lines 6843 OPPC - Optical Phase Conductor electrical resistance of the cable must be properly adapted to that of the substituted phase conductor. Generally, OPPCs are manufactured according to the same basic designs used for OPGW. However, since optical fibers are installed on high-voltage lines in the case of the OPPC, the splicing technology is different. Connections in the line must be carried out in a way that the cable, as well as the joint box, do not directly touch ground potential. A joint box can either be installed freely, hanging between the insulator strings on strong , or it can be placed on an insulator itself. At both ends of the line, electrical current and optical fibers must be separated. This can be done by special separators consisting of two splice closures placed at the top and bottom of an insulator. Like the OPGW, the OPPC has the advantage of combining functions without placing additional loads on the towers. 6844 MASS - Metallic Aerial Self-Supporting cable. This is a small-sized armored cable for additional installation at the center of towers. To minimize the additional load, weight and diameter are significantly reduced. The typical diameter range of MASS cables is between 9 > ond 12mm. The armoring is optimized according to span length and sag requirements only, because the cable does not have any electrical function. 6840 ADSS - All-Dielectric Self-Supporting Cables Another well-known cable solution for additional installation on medium and high-voltage lines is the All-Dielectric Self-Supporting (ADSS) cable. ADSS does not contain any metallic elements. The fibers are placed in several stranded loose plastic tubes which are covered by ‘one or two plastic jackets. To make the cable self-supporting, it contains strength elements made of aramid yarns. The excellent strength-to-weight ratio of this material ensures the low weight of ADSS and limits additional loads on towers. By adapting aramid content, spans of 800 m or even 1,000 m are possible, depending on permissible additional loads. v ALCATEL ARCHITECTS OF AN INTERNET WORLD ADSS is a universal solution for a large variety of applications. However, special attention must be paid if the cable is to be installed on high-voltage lines, to prevent dry-band arcing. Special sheathing material and software to calculate optimum placement on the towers make this technology usable for line voltages of up to about 275 kV. With a capacity of greater than 144 fibers, this cable technology offers a good opportunity to equip medium and high-voltage lines with optical fibers. B.1. Spread Sheet Data Bethel + 8 Villages Nuvista 10 MW Combined-Cycle Combustion Turbine at Bethel Villlage Sys. Losses 1999 = 15.00% SWGR Cost Per Mile = Phase Conversion Equipment % of Demand Village Sys. Losses 2020 = 8.00% Substation Cost each = Village Non-Fuel Expenses $/kwh,Sales = Bethel Sys. Losses | 8.00% Village Interface Gen. Admin Cost $/kwh 4 Transmission Losses 10.00% 1_phase to 3 phase SWGR & Gen. Admin Cost $/kwh Load Factor Villages 0.5 conversion KW SWGR O&M_$/kwh_ Load Factor Bethel 0.65: Generation O&M S/kw Loan Period Yr Est. Year 2006 Fuel Cost per Gal Interest Rate % District Heating O&M/kwh Tank Farm O&M/kwh _ 2007) 2008 2009 2010 Purchse Power Costs Bethel Utilities 990035. 1,207,106 1,246,700 1 286,919 S/kwh_ va 4,168,135 1,024,042 1,058,608 1 ,093,734 S/kW. va 4,245,071] 1,293,905 1,343,664 1,394,349) 1 445,959: Fuel inflaction Factor 804,398 838,210 872,718 907,922. 943,822 |General Inflation Factor oO} 527141 555808, 585, 186) 615,276 Discount Rate 685718 733,810: 758,444 763,471 808,889 667,563 | 688,006 708,754 729,805 751,160 772,820: 2,660,299 | 2, 751,629] 2,844,891 2,939,487 3,035,616 3,133,278 Wind Gen. $/KW_ 4,013,580) 6,198,872 9,104,881 9,431,074 9,763,012 40,100,697 Turbine Gen. Installation Cost $/kw 43,759,422 45,070,501 46,400,673) 47,749,938 | 49,118,295, 50,505,746) ‘Coal Plant Installation Cost $/kw ‘Avg. Heat Rate-BTU/kwh Turbine Avg. Heat Rate-BTU/kwh Coal Plant 4,013,580, 6,198,872 9,104,881 9,431,074 9,763,012 40,100,697 521,765: 785,190, 1,122,935 4,131,729 1,139,018] 1,144,746) Tank Farm $/gallon of s! 453,535: 698,406 1,022,782 1,056,280 1,090,203 | 4 124,544) (Available Waste Heat in Btu/hr (Average) Total Village Requirements 4,988,880. 7,682,469) 11,250,598 11,619,083 11,992,233) 12,369,987 Annual kwh's Sold 47,773,002. 51,269,373) 55,505,554) 57,181,012 58,881,307 60,606,443) ‘Avg. Heat Rate-BTU/kwh BU Diesel Bethe! kwh Sales 43,759,422, 45,070,501 46,400,673) 47,749,938) 49,118,295) 50,505,746) I Bethel Losses 3,500,754 3,605,640) 3,712,054) 3,819,995 3,929,464 4,040,460 Coal Cost per ton at 10,000 btu/ton Total Bethel Requirements 47,260,176. 48,676,141 50,112,727] 51,569,933, 53,047,759) 54,546,206 | Total System kwh Requirements [52,249,056 56,358,610) 61,363,325) 63,189,016 | 65,039,992 66,916,193, kW Demand 9,439 10,303 | 11,370 11,710) 12,054 12,404 | kwh Wind Gen. 0 0 0 0 0 0 KW_Wind Gen 0 0 0 oO 0 kwh Coal-Fired Gen. 0 0 0 oO 0 Bethel Utility Diesel @ 10% 5,224,906 5,635,661 6,318,902 6,691,619) 47,024,150. 50,722,749) 56,870,115) 60,224,573, 0 0 0 0 22,500 22,500 Coal-Fired Gen. $0 $0) Comb. Turbine Gen. $9,500,000 $9,500,000 Wind Gen. $0) District Heating System $500,000, $500,000. Tank Farm $4,000,000} $4,000,000) Subtotal $14,000,000) $14,000,000, SWGR System No.of Villages Connected Miles of T-Line 53) SWGR T-Line $5,381,000 $9,094,150 $9,094,150 $9,094,150 ‘Substations $1,530,000, $2,341,200 $2,341,200) $2,341,200] Village Modifications $918,000 $1,404,720 $1,404,720) $1,404,720 Phase Conversion Equip $105,239 $7,934,239 Subtotal pital Costs SWGR Bethel+8 1,934,239 ~__ $154,118 $159, 166) $164,277. $12,999,236 $13,004,347 6,999,236. 7,004,347 10f2 06/10/2002 Year 2005, 2006 | 2007 2008) 2009 2010, 4. Expenses |4.a Expenses Generation Debt Service $1,123,396 $1,123,396, $1,123,396) $1,123,396) $1,123,396) $1,123,396} Generation O&M $783,736 $870,741 $976,505 $1,035,725 $1,098,046) $1,163,613) District Heating System O&M $235,121 $253,614 $276,135 $284,351 $292,680) $301,123) Tank Farm O&M $261,245, $281,793 $306,817: $315,945. $325,200) $334,581 Diese! Fuel Cost $1.43 $1.49) $1.55) $1.61 $1.67 $1.74 Fuel Oil Gallons Turbine 2,691,962 2,903,694 3,161,545) 3,255,608 3,350,973) 3,447,639) Fuel Oil Gallons BU Diesels 386,189) 416,564 453,555) 467,049 480,730 494,598 Fuel Oil Expense Turbine $3,849,506) $4,318,373 $4,889,924 $5,236,826 $5,605,836 $5,998,249 Fuel Oil Expenses BU Diesels $552,250) $619,513 $701,508 $751,275 $804,213 $860,508 Total Fuel Oil Expenses $4,401,756 $4,937,887 $5,591,432) $5,988,101 $6,410,049) $6,858,757 Coal Expense $0 $0) $0 $o $0) $0) Admin $391,868. $422,690) $460,225) $473,918 $487,800] $501,871 Power Purchases from Bethel Utilities $0 $0 $0 $0 $0 $0) Subtotal $7,197,122 $7,890,120 $8,734,510 $9,221,436) $9,737,171] $10,283,342. SWGR System Debt Service $310,406 $636,664 $1,042,687, $1,043,092) $1,043,502 $1,043,918 SWGR O&M $74,833 $118,694 $179,036) $190,447 $202,460, $215,103} Admin. $37,417 $59,347 $89,518) $95,224 $101,230) $107,552 Subtotal $422,655: $814,705) $1,311,242) $1,328,763) $1,347,193) $1,366,572 Total Expenses $7,619,777 $8,704,825| $10,045,752] $10,550,199] $11,084,364] $11,649,914 6. Power Cost Avg. Busbar Cost/kwh - Bethel $0.151 $0.154 $0.157 $0.161 $0.165, $0.170 Avg. Cost $/kwh SWGR System $0.105, $0.131 $0.144 $0.141 $0.138) $0.135) ‘Avg. Busbar Costkwh - Villages $0.256 '$0.285| $0:301 $0.302 $0.303 $0.305 B.1 Additional Non-Fuel Expenses Villages $0.080. $0.082 $0,085) $0.087 $0.090) $0.093, B.2 Average Cost to Village Consumer $0.336, $0.368 $0.386 $0.390 $0.393) $0.398) 16. Waste Heat Recovery Available Waste Heat For Sale (1,000,000 Btu) 105,120 105,120 105,120 105,120 105,120) 105,120) (Diese! Fuel Gal Equivalent) 761,739 761,739 761,739 761,739 761,739 761,739 Waste Heat Sales @90% Fuel Cost $980,358 $1,019,573) $1,060,355) $1,102,770 $1,146,861 $1,192,756) 7. Power Coats with Waste Heat (WH) Offeet [Rate Reduction $/kwh from WH Sales $0.012 $0.012 $0.012 $0.012 $0.013 $0.013 Reserve Account $/kwh $0.007 $0.007. ‘$0,007 $0.007, $0.007 $0.007, Busbar Cost $/kwh w/ WH Offset A. Bethel $0.146 $0.149) $0.152 $0.156 $0.160, $0.164 B. Villages $0.251 $0.280) $0.296 $0.297 $0.298 $0.299 8.1 Average Cost to Village Consumer $0.331 $0.363 $0381 $0.384 $0.388 $0,302 including Non-Fuel Expenses 18. Present Worth Costs Yr 2000 Dollars PW Factor 0.871 0.842 0.814 0.786 0.759 0.734, PW Avg. Costikwh A. Bethel Busbar $/kwh $0.127 $0.125 $0.124 $0.123, $0.121 $0.120) B. Villages B.1 Village Busbar S/kwh $0219 $0.236 $0.241 $0.233 $0.226 30.219 B. 2 Village Avg.Cost including non-fuel costs$/ikwh $0.268 $0.305 $0310 $0.302 $0.294 $0.287 IPW_Power Cost A. Bethel Busbar $5,992,521 $5,647,092) $5,755,120) $5,853,983] $5,956,409 $6,062,394 B. Villages B.1 Village Busbar $877,236, $1,462,645, $2,195,983 $2,200,614 $2,207,001 $2,215,121 B. 2 Village Avg Cost including non-fuel costs $1,157,044 $1,892,714 $2,824,615 $2,848,622 $2,874,576 $2,902,449 Accumlated PW Power Cost A. Bethel $5,992,521] $11,639,614] $17,394,733] $23,248,716] $29,205,125] $35,267,519) B. Villages 8.1 Village Busbar $877,236 $1,754,472 $3,217,117 $5,413,100) $7,613,714) $9,820,716) B. 2 Village Avg Cost including non-fuel costs $1,157,044 $3,049,758) $5,874,374 $8,722,996] $11,597,572! _ $14,500,021 C. Bethel + Villages without non-fuel Cs $6,869,757] $13,304,085] $20,611,850] _ $28,661,816] $36,818,839| $45,088,235) Bethel + Vill with, fuel Costs: 57,149, 566 14,689,372 107, 4,971,711 802,697. 19,767,540) SWGR Bethel+8 202 06/10/2002 Bethel + 8 Villages Purchase Power from Bethel Utilities at Three Phase Rate \Nuvista Supplied Fuel Oil Village Sys. Losses 1999 = 15.00% 'SWGR Cost Per Mile = Phase Conversion Equipment % of Demand Village Sys. Losses 2020 = 8.00% ‘Substation Cost each = Village Non-Fuel Expenses $/kwh,Sales = Bethel Sys. Losses | 8.00% Village Interface |Gen. Admin Cost $/kwh Expected Load Growth Transmission Losses 10.00% 1 phase to 3 phase SWGR & Gen. Admin Cost $/kwh Load Factor Villages 0.5) conversion equip./kW ISWGR O&M_$/kwh Load Factor Bethel 0.65) Generation O&M $/kw Loan Period Yr Interest Rate % Est. Year 2005 Fuel Cost per Gal District Heating O&M/kwh Tank Farm O&M/kwh 2006, 2008, 2009 2010 Ey Purchse Power Costs Bethe! Utilities 0 1,207,106, 1,246,700 1,286,919 Skwh Tariff Rate 0 1,024,042 1,058,608 1,093,734 S/kW Tariff Rate 41,245,071 1,343,664 1,394,349] 1,445,959 Fuel Inflaction Factor 804,398: 872,718 907,922: 943,822 General Inflation Factor 0 555808 | 585,186. 615,276 Discount Rate 709568 758,444 783,471 688,006 | 729,805: 751,160: 772,820: ORI CICIES Coes 2,751,829) 2,939,487, 3,035,616 | 3,133,278) Wind Gen. $/KW. 6, 198,872 9,431,074 9,763,012) 40,100,697 Turbine Gen. Installation Cost S/kw 45, 070,501 47,749,938. 49,118,295, 50,505,746) Coal Plant Installation Cost $/kw Avg. Heat Rate-BTU/kwh Turbine [Avg. Heat Rate-BTU/kwh Coal Plant Village kwh Sales 6, 198,872 9,104,881 9,431,074) 9,763,012 10,100,697, Village System Losses 785,190! 1,122,935 1,131,729 1,139,018} 1,144,746 Tank Farm $/gallon of storage Transmission Losses 698, 406 41,022,782 1,056,280 1,090,203} 1,124,544 [Available Waste Heat in Btu/hr (Average) Total Village Requirements 7,882,469 11,250,598 11,619,083! 71,992,233} 12,369,987, Avg. Heat Rate-BTU/kwh BU Diesel Bethel kwh Sales 45,070,501 46,400,673) 47,749,938) 49,118,295) 50,505,746 Bethel Losses 3,605,640, 3,712,054 3,819,995) 3,929,464 4,040,460 Coal Cost per ton at 10,000 btu/ton Total Bethel Requirements 48,676,141 50,112,727 51,569,933) 53,047,759 54,546,206 Total System kwh Requirements 56, 358,610 61,363,325) 63,189,016 65,039,992 66,916,193, kW Demand 10,303 11,370! 14,710 12,054 12,404 kwh Wind Gen. 0 KW_Wind Gen kwh Coal-Fired Gen. 0 Bethel Utility Diese! 63,189,016 kwh Combustion Turbine Gen. 15,000 Coal 10,000 Turbine Wind Gen. Bethel Utilities Diesel jy Blololo Total install Capacity 8 BB lel Bil. 3. Capital Costs Generation Coal-Fired Gen. Comb. Turbine Gen. Wind Gen. District Heating System Tank Farm Subtotal sisisisisis ‘SWGR System No.of Villages Connected Miles of T-Line Slo| [sisisisisis Slo) (Sisisisisis Blo! [Sisisisisis Blo) [sisisisisis) SWGR T-Line $5,381,000 Substations $1,530,000) Village Modifications $918,000 Phase Conversion Equip 105,239] Subtotal $7,934,239] Total Capital Costs nuvistaoilBUpower3pSWGR+8 06/10/2002 Generation Debt Service $0) $0) $0 $0 $0 $0 Generation O&M $783,736 $870,741 $976,505 $1,035,725) $1,098,046 $1,163,613 District Heating System O&M $0) $0 $0) $0 $0 $0) Tank Farm O&M $0 $0 $0) $0) $0 $0) Diesel Fuel Cost $1.53 $1.59) $1.65 $1.72 $1.79 $1.86 Fuel Oil Gallons Turbine 0 0 0 0) 0 0 Fuel Oil Gallons BU Diesels 3,861,887 4,165,636 4,535,550} 4,670,493 | 4,807,304 4,945,979 Fuel Oil Expense Turbine $0 $0 — $0 $0) $0) $0) Fuel Oil Expenses BU Diesels $5,908,687 $6,628,361 $7,505,646 $8,038,113 $8,604,514 $9,206,837 Total Fuel Oil Expenses $5,908,687 $6,628,361 $7,505,646 $8,038,113 $8,604,514 $9,206,837 Coal Expense $0 $0 $0 $0) $0 $0 Admin. $391,868 $422,690 $460,225 $473,918 $487,800 $501,871 Subtotal $7,084,290 $7,921,791 $8,942,376 $9,547,756] $10,190,360] _ $10,872,321 'SWGR System Debt Service $310,406 $636,664 $1,042,687 $1,043,092 $1,043,502 $1,043,918, SWGR O&M $74,833 $118,694 $179,036 $190,447 $202,460 $215,103 Admin. $37,417 $59,347 $89,518 $95,224 $101,230 $107,552 Subtotal $422,655 $814,705 $1,341,242 $1,328,763 $1,347,193) $1,366,572 Total Expenses $7,506,946 $8,736,496| $10,253,618] $10,876,519] $11,537,553] $12,236,893 5. Power Cost A. Bethel - Avg. Busbar Cost $/kwh $0.138 $0.144 $0.151 $0.157 $0.162 $0.168 Avoided Cost $/kwh $0.113 $0.118 $0.122 $0.127 $0.132 $0.138 B. Villages Avg. Purchased Power Cost $/kwh from BU, 3-phase R, $0.167 $0.172 $0.177 $0.181 $0.187 $0.192 Avg. Cost $/kwh SWGR System $0.105, $0.131 $0.144 $0.141 $0.138, $0.135 ‘Avg. Busbar Costkwh - Villages $0.273 $0.303 $0321 $0.322 $0.325 $0.327 Additional Non-Fuel Expenses Villages $0.080) $0.082, $0,085, $0.087 $0.090) $0.093 Average Cost to Village Consumer $0.353) $0.386, $0.405, $0.410 $0.415) $0.420 6. Waste Heat Recovery Available Waste Heat For Sale (1,000,000 Btu) 0 0 0 0 0 0 (Diese! Fuel Gal Equivalent) 0! 0 0} 0 0! 0 Waste Heat Sales @90% Fuel Cost $0 $0 $0 $0 So] $0 17. Power Costs with Waste Heat (WH) Offset Rate Reduction $/kwh from WH Sales $0.000, $0.000 $0.000) $0.000. $0.000) $0.000) Busbar Cost $/kwh wi WH Offset C A. Bethel $0.138 $0.144 $0.151 $0.157 $0.162 $0.168) B. Villages B.1 Village Busbar $/kwh $0.273) $0.303 $0.321 $0.322 $0.325) $0.327, B. 2 Village Avg.Cost including non-fuel costs$/kwh $0.353) $0.386 $0.405 $0.410 $0.415 $0.420) 18. Present Worth Costs Yr 2000 Dollars |PW Factor 0.871 0.842 0.814 0.786 0.759 0.734] PW Avg. Costkwh A. Bethel Busbar $/kwh $0.120) $0.122 $0.123 $0.123 $0.123 $0.123, B. Villages B.1_ Village Busbar $/kwh $0.238 $0.255 $0.261 $0.253 $0.246 $0.240 B. 2 Village Avg.Cost including non-fuel costs$/kwh $0.307 $0.325) $0.330 $0.32 $0.315 '$0.308 IPW_Power Cost A. Bethel Busbar $5,690,300 $5,478,219 $5,700,123) $5,874,280) $6,051,679 $6,232,355 B. Villages B.1 Village Busbar $1,185,266) $1,961,716) $2,933,948 $2,943,736 $2,955,437 $2,969,015) B. 2 Village Avg.Cost including non-fuel costs $1,533,067 $2,494,715, $3,710,728 $3,742,082 $3,775,441 $3,810,763 Accumlated PW Power Cost A. Bethel $5,690,300] $11,168,519] $16,868,642| $22,742,923] $28,794,602] $35,026,957 B. Villages B.1 Village Busbar $1,185,266 $2,370,532 $4,332,248 $7,266,196] $10,209,932] $13, 165,369) B. 2 Village Avg. Cost including non-fuel costs $1,533,067 $4,027,783, $7,738,511 $11,480,593] $15,256,034] $19,066,797, C. Bethel + Villages without non-fuel costs $6,875,566] $13,539,050] $21,200,890] $30,009,119] _ $39,004,534] _ $48, 192,326) Bethel + Vil with non-fuel costs 57,223,367. 15,196,301 4,607,153) 223,515 050,636. 093,754 nuvistaoilBUpower3pSWGR+8 20f2 06/10/2002 Bethel + 8 Villages Purchase Power from Bethel Utilities at Three Phase Rate Villlage Sys. Losses 1999 = 15.00%, SWGR Cost Per Mile = Phase Conversion Equipment % of Demand Village Sys. Losses 2020 = 8.00% Substation Cost each = Village Non-Fuel Expenses $/kwh, Sales = Bethel Sys. Losses | 8.00% Village Interface Gen. Admin Cost $/kwh I Expected Load Growth Transmission Losses 10.00% | 1_phase to 3 phase SWGR & Gen. Admin Cost $/kwh Load Factor Villages 0.5) [conversion equip./kW. SWGR O&M _$/kwh Load Factor Bethel 0.65 Generation O&M S/kw_ Loan Period Yr Est . Year 2006 Fuel Cost per Gal Interest Rate % District Heating O&M/kwh Tank Farm O&M/kwh, 2006 2007 2008 2009 2010 | 990035 1,207,106 1,246,700| 1,286,919] 0 4,168,135 1,024,042 1,058,608 1,093,734 1,245,071 4,293,905 1,343,664 1,394,349 1,445,959 804,398 838,210) 872,718 907,922 943,822, 0 527141 555808. 585, 186| 615,276 709568) 733,810] 758,444 783,471 808,889) 688,006 708,754 729,805; 751,160] 772,820 2,751,829| 2,844,891 2,939,487 3,035,616] 3,133,278 Total Villages 6,198,872 9,104,881 9,431,074 9,763,012 10,100,697 Bethel 45,070,501 46,400,673 47,749,938 | 49,118,295, 50,505,746) 1. Load Requirements Village kwh Sales 6,198,872 9,104,881 9,431,074 9,763,012 10,100,697 Village System Losses 785,190) 1,122,935) 1,131,729] 1,139,018. 1,144,746 | Transmission Losses 698,406 1,022,782 1,056,280) 1,090,203 1,124,544 Total Village Requirements 7,682,469 11,250,598 | 11,619,083. 11,992,233, 12,369,987 Bethe! kwh Sales 45,070,501 46,400,673) 47,749,938, 49,118,295, 50,505,746 Bethe! Losses 3,605,640, 3,712,054 3,819,995 3,929,464 4,040,460 Total Bethel Requirements 48,676,141 50,112,727, 51,569,933 53,047,759 54,546,206 Total System kwh Requirements 56,358,610) 61,363,325) 63,189,016 65,039,992, 66,916,193) kW Demand 10,303, 11,370) 11,710 12,054 | 12,404 kwh Wind Gen. 0 0 0 KW_ Wind Gen 0 0 0 kwh Coal-Fired Gen. 0 0 0 Bethel Utility Diesel 63,189,016, 65,039,992 66,916,193, kwh Combustion Turbine Gen. 0 0 0 12. Generation Capacity 15,000 Coal 10,000 Turbine Wind Gen. Bethel Utilities Diesel Total Install Capacity Slololo! Blololo! Be a Ballot 3. Capital Costs Generation Coal-Fired Gen. Comb. Turbine Gen. Wind Gen. District Heating System Tank Farm Subtotal ‘SWGR System No.of Villages Connected Miles of T-Line SWGR T-Line Substations Village Modifications sisisisisis sisisisisis Blo! Sisisisisis! sisisisisis Slo [sisisisisis| Blo! [Sisisisisis $154 118, $12,994,188 12,994,188 BUpower3pSWGR +8 1of2 06/10/2002 Year 2005 2006 | 2007 2008 | 2009) 2010) 14. Expenses '4.a Expenses Generation Debt Service $0) $0) $0) $0 $0 $0) Generation O&M $783,736 $870,741 $976,505 $1,035,725 $1,098,046) $1,163,613) District Heating System O&M $0 $0) $0 $0 $0 $0) Tank Farm O&M $0 $0) $0 $0) $0 $0) Diese! Fuel Cost $2.30 $2.39) $2.49) $2.59 $2.69 $2.80 Fuel Oil Gallons Turbine 0 0 0 0 0 0 Fuel Oil Gallons BU Diesels 3,861,887 4,165,636) 4,535,550 4,670,493 4,807,304 4,945,979) Fuel Oil Expense Turbine $0 $0 $0 $0 $0 $0) Fuel Oil Expenses BU Diesels $8,882,339) $9,964,202] $11,282,997] $12,083,438] $12,934,890] $13,840,343) Total Fuel Oil Expenses $8,882,339 $9,964,202] $11,282,997] $12,083,438] $12,934,890] $13,840,343 Coal Expense $0. $0) $0) $0. $0 $0 Admin $391,668. $422,690. $460,225) $473,918 $487,800 $501,871 Subtotal $10,057,943] $11,257,632] $12,719,727] $13,593,081| $14,520,737] $15,505,827. SWGR System Debt Service $310,406. $636,664 $1,042,687 $1,043,092, $1,043,502 $1,043,918 SWGR O&M. $74,833) $118,694 $179,036) $190,447 $202,460 $215,103 Admin. $37,417 $59,347 $89,518) $95,224 $101,230 $107,552 Subtotal $422,655 $814,705) $1,311,242 $1,328,763) $1,347,193) $1,366,572 Total Expenses $10,480,599] $12,072,337] $14,030,969] $14,921,844] $15,867,930] $16,872,399 5. Power Cost A. Bethel - Avg. Busbar Cost/kwh - Bethel $0.196 $0.205, $0.215 $0.223 $0.231 $0.240) B. Villages Avg. Purchased Power Cost $/kwh from BU, 3-phase RL $0.209) $0.216 $0.223) $0.230, $0.238) $0.246 Avg. Cost $/kwh SWGR System $0.105) $0.131 $0.144 $0.141 $0.138 $0.135 Avg. Busbar Cost/kwh - Villages $0.314 $0.347 $0.367, $0.371 $0.376 $0.381 Additional Non-Fuel Expenses Villages $0.080) $0.082 $0.085 $0.087, $0.090 $0.093 Average Cost to Village Consumer $0.304 $0.430 $0.452 $0.459 $0.468 $0.474 16. Waste Heat Recovery Available Waste Heat For Sale (1,000,000 Btu) 0 0 a 0 0 ol (Diesel Fuel Gai Equivalent) 0 0} 0 0 0} 0} Waste Heat Sales @90% Fuel Cost $0} $0 $0 $0 $0) $0 7. Power Costs with Waste Heat (WH) Offset Rate Reduction $/kwh from WH Sales $0.000 $0.000) $0.000) $0.000 $0.000) $0.000 Busbar Cost $/kwh w/ WH Offset A Bethel $0.196 $0.205) $0.215) $0.223 $0.231 $0.240) B. Villages B.1_ Village Busbar $/kwh $0.314 $0.347 $0.367 $0.371 $0.376) $0.381 B. 2 Village Avg.Cost including non-fuel costs$/kwh $0.304 $0.430) $0.452 $0.459) $0.466 | $0.474 18. Present Worth Costs Yr 2000 Dollars PW Factor 0.871 0.842 0.814 0.786 0.759 0.734 PW Avg. Cost/kwh A. Bethel Busbar $/kwh $0.171 $0.173 $0.175) $0.175 $0.176 $0.176 B. Villages B.1_ Village Busbar $/kwh $0.274) $0.292 $0.298 $0.292 $0.285, $0.280) B. 2 Village Avg.Cost including non-fuel costs$/kwh $0.344 $0.362 $0,368 $0.360 $0.354 $0.348 IPW_Power Cost A. Bethe! Busbar $8,078,821 $7,785,080) $8,107,914 $8,363,177 $8,623,330 $8,888,426 B. Villages 8.1 Village Busbar $1,366,561 $2,246,180 $3,358,113) $3,389,467 $3,423,246 $3,459,414) B. 2 Village Avg.Cost including non-fuel costs $1,714,362 $2,779,179) $4,134,893 $4,187,812 $4,243,251 $4,301,163 Accumlated PW Power Cost A. Bethel $8,078,821] _$15,863,901| $23,971,814] $32,334,991] $40,958,321] $49,846,747 B. Villages B.1 Village Busbar $1,366,561 $2,733,121 $4,979,301 $8,337,414] $11,726,881] $15,150,127 B. 2 Village Avg. Cost including non-fuel costs $1,714,362 $4,493,541 $8,626,434] $12,816,247| $17,059,497] $21,360,660 C. Bethel + Villages without nonfuel costs $9,445,382] $18,597,022] $28,951,116] $40,672,406] $52,685,202] $64,996,875 Bethel + Vi with non-fuel costs 39,793,183 0,357,442 249 151,238 017,819 1,207,407, BUpower3pSWGR+8 20f2 06/10/2002 Bethel + 8 Villages Purchase Power from Bethel Utilities at Single Phase Rate \Villlage Sys. Losses 1999 = 15.00% SWGR Cost Per Mile = $400,000 [Phase Conversion Equipment % of Demand 15.00% Village Sys. Losses 2020 = 8.00% ‘Substation Cost each = $250,000) Village Non-Fuel Expenses $/kwh, Sales = '$0.080 Bethel Sys. Losses | 8.00% Village Interface $150,000) Gen. Admin Cost kwh | 0.0075) Expected Load Growth ‘Transmission Losses 10.00% 1 phase to 3 phase $400 SWGR & Gen. Admin Cost $/kwh $0.0075 Load Factor Villages = 05 [conversion equip kW. ISWGR O&M _S/kwh. $0.015 Load Factor Bethel = 0.65) Generation O&M Sikw $0.0150 Loan Period Yr 20 Est. Year 2005 Fuel Cost per Gal $2.30) Interest Rate % 5.00% District Heating O&M/kwh $0.0050 Tank Farm O&M/kwh $0.0050 Year 2005) 2006 2007 2008 2009 2010 kwh Sales # Purchse Power Costs Bethel Utilities Akiachak 1 0 0 990035] 1,207,106 1,246,700 1,286,919 'sikwh Tariff Rate Akiak 2 0 0 1,168,135) 1,024,042 1,058,608 1,093,734 skW Tariff Rate Kwethluk 3 0 1,245,071 1,293,905: 1,343,684 1,394,349) 1,445,959 Fuel Inflaction Factor 40% Napaskiak 4 0 804,398 838,210) 872,718 907,922 943,822 [General Inflation Factor 3.0% Tuluksak 5 0 0 527141 555608 585,186 615,276| Discount Rate 3.5% Napakiak 6 685718 709568. 733,810 758,444 783,471 806,889) Atmautluak 7 667,563 688,006 708,754 729,805 751,160 772,820| Kasigluk/Nunapitchuk 8 2,660,299 2,751,829 2,844,891 2,939,487 3,035,816) 3,133,278 Wind Gen. KW. $2,000] Total Villages 4,013,580 6,198,872 9,104,881 9,431,074 9,763,012| 10,100,697 Turbine Gen. installation Cost $/ixw = $950) Bethe! 9| _43,759,422|45,070,501| 46,400,673] 47,749,938 49,118,205] 50,505,746 ‘Coal Plant installation Cost $/kw $3,500| Avg. Heat Rate-BTU/kwh Turbine 7,900] 1. Load Requirements Avg. Heat Rate-BTU/kwh Coal Plant 15,500] Village kwh Sales 4,013,580 6,198,872 9,104,881 9,431,074 9,763,012] 10,100,697 Village System Losses 521,765 785,190 1,122,935: 1,131,729 1,139,018 1,144,746) Tank Farm S/galion of storage $1.50) Transmission Losses 453,535 | 698, 406| 1,022,762: 1,056,280 1,090,203 1,124,544 [Available Waste Heat_in Btu/hr (A\ 12,000,000} Total Village Requirements 4,988,880 7,682,469| 11,250,598] 11,619,083! 11,992,233] 12,369,967 Avg. Heat Rate-BTU/kwh BU Diesel 10,200 Bethel kwh Sales 43,759,422|"45,070,501| _ 46,400,673| 47,749,938 49,118,295] 50,505,746 I I Bethel Losses 3,500,754 3,605,640 3,712,054 3,819,995) 3,929,464 4,040,460 (Coal Cost per ton at 10,000 btu/ton $63 Total Bethel Requirements 47,260,176] 48,676,141| __50,112,727| 81,569,033] 53,047,759| 54,546,206 Total System kwh Requirements 52,249,056] 56,358,610| _61,363,325| —_63,169,016| __65,039,992| 66,916,193 kW Demand 9,439 10,303) 14,370 11,710 12,054 12,404 kwh Wind Gen. 0 0 0 ) 0 0 KW_Wind Gen 0 0 0 0 0 0 kwh Coal-Fired Gen. 0 0 0 0 0 0 Bethel Utility Diesel 52,249,056] 56,358,610| 61,363,325] 63,169,016 _65,039,902| 66,916,193 kwh Combustion Turbine Gen 0 0 0 0 0 0 |2. Generation Capacity 15,000 Coal 0 0 0 0 0 0 10,000 Turbine 0 0 oO 0 0 0 Wind Gen. 0 0 0 0 0 0 Bethel Utilities Diese! 12,500 12,500) 12,500 12,500 12,500 12,500 Total install Capacity 12,500 12,500 12,500 12,500 12,500 12,500 | 3. Capital Costs Generation Coal-Fired Gen. $0 $0 $0 $0 $0 $0) Comb. Turbine Gen. 30 $0 $0 $0 $0 $0] Wind Gen. $0) $0 $0) $0 $0 $0) District Heating System $0 $0 $0 $0 $0 $0 Tank Farm $0) $0) $0) $0 $0 $0 Subtotal $0 $0 $0 $0 $0 $0 Tt SWGR System No.of Villages Connected 2 5) 8 8 8 8 Miles of T-Line 26 53 88 88 88 88 SWGR T-Line ‘$2,600,000 |" $5,381,000 |" $9,004,150 | $9,094,150 |" $9,094,150 | $9,094,150 Substations $750,000| $1,530,000] $2,341,200] $2,341,200] $2,341,200] $2,341,200 —I Village Modifications $450,000) $918,000] $1,404,720] $1,404,720|"$1,404,720| $1,404,720! Phase Conversion Equip $68,341 $105,239) $154,118) $159, 166 $164,277 $169,452 Subtotal $3,868,341| $7,934,239 $12,994,188] $12,999,236] $13,004,347| $13,009,522 Total Capital Costs 868,341 7,934,239 | $12,994,188 | $12,999,236 3,004,347 | $13,009,522 BUpower1pSWGR+8 10f2 06/10/2002 Year 2005, 2006, 2007 2008: 2009) 2010) 4. Expenses: |4.a Expenses Generation Debt Service $0 $0 $0 $0 $0 $0 Generation O&M $783,736 $870,741 $976,505, $1,035,725 $1,098,046) $1,163,613 District Heating System O&M $0 $0 $o $0 $0) $0) Tank Farm O&M $0 $0 $0 $0 $0 $0 Diesel Fuel Cost $2.30 $2.39 $2.49) $2.59 $2.69 $2.80 Fuel Oil Gallons Turbine 0 0 0} 0 0 0 Fuel Oil Gallons BU Diesels 3,861,887 4,165,636] 4,535,550) 4,670,493} 4,807,304 4,945,979) Fuel Oil Expense Turbine $0 $0 $0) $0) $0 $0 Fuel Oil Expenses BU Diesels $8,882,339 $9,964,202] $11,282,997] $12,083,438] $12,934,890] $13,840,343, Total Fuel Oil Expenses $8,882,339] $9,964,202] _ $11,282,997| $12,083,438] $12,934,690] _ $13,840,343) Coal Expense $0 i $0] $0. $0. $0) $0) Admin $391,868 $422,690] | $460,225 $473,918 $487,800 $501,871 Subtotal $10,057,943] $11,257,632 $12,719,727] $13,593,081 $14,520,737| __ $15,505,827 SWGR System Debt Service $310,406 $636,664 $1,042,687 $1,043,092 $1,043,502 $1,043,918) SWGR O&M. fel $74,833 $118,694 $179,036, $190,447 $202,460) $215,103) Admin. $37,417 $59,347 $89,518 $95,224 $101,230) $107,552 Subtotal $422,655 $814,705 $1,311,242 $1,328,763 $1,347,193) $1,366,572 Total Expenses $10,480,599] $12,072,337] $14,030,969] $14,921,844] $15,867,930] $16,872,399) 5. Power Cost A Bethel - Avg. Busbar Cost/kwh - Bethel $0.196 $0.205 $0.215 $0.223 $0.231 $0.240 B. Villages Avg. Purchased Power Cost $/kwh from BU, 1-phase RL $0.289) $0.296 $0.303 $0.310 $0.318 $0.326) Avg. Cost $/kwh SWGR System $0.105 $0.131 $0.144 $0.141 $0.138 $0.135) Avg. Busbar Cost/kwh - Villages $0.394 $0.427 $0.447 $0.451 $0.456. $0.461 Additional Non-Fuel Expenses Villages $0.080 $0.082, $0.085) $0.087 $0.090) $0.093) Average Cost to Village Consumer $0.474 $0.510) $0.532, $0.539 $0.546) $0.554 6. Waste Heat Recovery Available Waste Heat For Sale (1,000,000 Btu) 0 0} 0} 0 0 0} (Diesel Fuei Gal Equivalent) 0 0| 0 0} 0 0 Waste Heat Sales @90% Fuel Cost $0) $0) $0 $0} $0 $0 '7. Power Costs with Waste Heat (WH) Offset Rate Reduction $/kwh from WH Sales $0.000 ‘$0.000) $0.000 $0.000 $0.000 $0.000, Busbar Cost $/kwh w/ WH Offset A. Bethel $0.196 $0.205| $0.215) $0.223 $0.231 $0.240) B. Villages B.1_ Village Busbar $/kwh $0.394 $0.427 $0.447 $0.451 $0.456 | $0.461 B. 2 Village Avg.Cost including non-fuel costs$/kwh $0.474 $0.510) $0.532 $0.539 $0.546) $0.554 8. Present Worth Costs Yr 2000 Dollars PW Factor 0.871 0.842) 0.814 0.786 0.759 0.734) PW Avg. Costkwh A. Bethe! Busbar $/kwh $0.171 $0.173 $0.175 $0.175 $0.176 $0.176 B. Villages B.1_ Village Busbar $/kwh $0.344 $0.360) $0.364) $0.355 $0.346) $0.338) B. 2 Village Avg.Cost including non-fuel costs$/kwh $0.413 $0.429 $0.433 $0.423 $0.415 $0.406 IPW_Power Cost A. Bethe! Busbar $8,078,821 $7,785,080) $8,107,914 $8,363,177 $8,623,330 $8,888,426 | B. Villages B.1 Village Busbar $1,714,255, $2,763,495 $4,090,077, $4,119,841 $4,151,585, $4,185,290) B. 2 Village Avg.Cost including non-fuel costs $2,062,057| $3,206,494] $4,866,857| $4,918,187] $4,971,589] __ $5,027,038) Accumlated PW Power Cost A. Bethel $8,078,821 $15,863,901] $23,971,814] $32,334,991] $40,958,321| $49,846,747 B. Villages B.1 Village Busbar $1,714,255 $3,428,510 $6,192,005] _ $10,282,082] $14,401,923] $18,553,508 B. 2 Village Avg.Cost including non-tuel costs $2,062,057] $5,368,551] _ $10,225,408] $15,143,594] $20,115,184] $25,142,222 C. Bethel + Villages without non-fuel costs $9,793,076] $19,292,411] _ $30,163,820] $42,617,073] $55,360,244] $68,400,255 Bethel + Vil h fuel costs. 10,140,878 | 4,222,451 197,222 7,478,585, 1,073,505, 574,988,969 BUpower1pSWGR+8 20f2 06/10/2002 Bethel + 8 Villages Nuvista 10 MW Combined-Cycie Combustion Turbine at Bethel, Grants Village Sys. Losses 1999 = 15.00% SWGR Cost Per Mile = Phase Conversion Equipment % of Demand Village Sys. Losses 2020 = 8.00% Substation Cost each = Village Non-Fuel Expenses $/kwh, Sales = Bethel Sys. Losses | 8.00% Village interface Gen. Admin Cost $/kwh I Transmission Losses 10.00%: 1 phase to 3 phase SWGR & Gen. Admin Cost $/kwh Load Factor Villages = 05 conversion equip./kW ISWGR O&M_ $/kwh Load Factor Bethel = 0.65) Generation O&M S/kw Loan Period Yr Est . Year 2005 Fuel Cost per Gal Interest Rate % Grants District Heating O&M/kwh Tank Farm O&M/kwh 2006 2007, 2008 2009) 2010 Purchse Power Costs Bethel Utilities 0 0} 1,207,106 | 1,246,700) 1,286,919) 'SAcwh_ $0.00) 0 0 1,024,042 1,058,608 1,093,734 SW $0.00 1,245,071 1,293,905, 1,343,664 1,394,349 1,445,959) Fuel Inflaction Factor 804,396 | 838,210 872,718) 907,922 943,822 General Inflation Factor 9 i) 0) 585,186 615,276 Discount Rate 0 733,810) 758,444 783,471 808,889 688,006 708,754 729,805 751,160 772,820 2,751,829) 2,844,891 2,939,487 3,035,616 | 3,133,278 Wind Gen. $/KW_ 5,489,304 6,419,570) 8,875,266 | 9,763,012 10,100,697 ‘Turbine Gen. installation Cost $/kw 45,070,501 46,400,673 47,749,938, 49,118,295, 50,505,746 ‘Coal Plant Installation Cost $/kw Avg. Heat Rate-BTU/kwh Turbine Avg. Heat Rate-BTU/kwh Coal Plant Village kwh Sales 5,489,304 6,419,570 8,875,266 | 9,763,012 10,100,697 | Village System Losses Z 695,312, 791,747 1,065,032 4,139,018 1,144,746) ‘Tank Farm $/galion of storage Transmission Losses 376,048 618,462 721,132, 994,030 1,090,203 | 1,124,544 [Available Waste Heat in Btu/hr (Average) Total Village Requirements 4,136,532 6,803,077 7,932,449) 10,934,328. 11,992,233} 12,369,987 I Annual kwh’s Sold 47,087,284 50,559,805, 52,820,243) 56,625,204 58,881,307 60,606,443 Avg. Heat Rate-BTU/kwh BU Diesel Bethel kwh Sales 43,759,422 45,070,501 46,400,673 47,749,938) 49,118,295 50,505,746, I Bethel Losses 3,500,754 3,605,640, 3,712,054) 3,819,995, 3,920,464 4,040,460| _ Coal Cost per ton at 10,000 btu/ton Total Bethe! Requirements 47,260,176 48,676,141 50,112,727, 51,569,933) 53,047,759 54,546,206 | Total System kwh Requirements 51,396,708 55,479,219) 58,045,176 62,504,261 65,039,992 66,916,193} kW Demand 9,244 10,102 10,612 11,553 12,054 12,404 kwh Wind Gen. 0 0 oO 0} 0 oO KW_ Wind Gen 0 0 0 oO oO O kwh Coal-Fired Gen. 0} 0 0 0 0 0 Bethe! Utility Diese! @ 10% 5,139,671 5,547,922) 6,503,999) 6,691,619 kwh Combustion Turbine Gen. 46,257,037 49,931,297, 58,535,993) 60,224,573, | 15,000 Coal 0 0} 10,000 Turbine 10,000 10,000 Wind Gen. 0 0 Bethe! Utilities Diese! 12,500 Total install Capacity 22,500 Generation Coal-Fired Gen. Comb. Turbine Gen. Wind Gen. District Heating System Tank Farm Subtotal SWGR System No.of Villages Connected Miles of T-Line SWGR T-Line Substations Village Modifications Phase Conversion Equip § Is 3 3. Capital Costs sisisisisis SisisisisiSisiu| isisisisisis SisisisisiSigio| lsigisisisis! SigigigigiS|a|.| isigisisisis SisisisisiSisio| [gigigigigis Sigisisis/Sigio| lsisigisisis! Sigisisisiial. SWGR Bethel+8,grants 1of2 06/10/2002 Year 2005, 2006 2007 2008 2009) 2010 4. Expenses |4.a Expenses Generation Debt Service $0 $0) $0) $0 $0 $0 Generation O&M $770,951 $857,154 $923,702 $1,024,501 $1,098,046 $1,163,613 District Heating System O&M $231,285 $249,656 $261,203 $281,269 $292,680 $301,123 Tank Farm O&M $256,984 $277,396 $290,226 | $312,521 $325,200) $334,581 Diesel Fue! Cost $1.43 $1.49 $1.55) $1.61 $1.67 $1.74 Fuel Oil Gallons Turbine 2,648,048 2,858,386, 2,990,588) 3,220,328 3,350,973 3,447,639) Fuel Oil Gallons BU Diesels 379,889) 410,064 429,030) 461,988 480,730) 494,596 | Fuel Oil Expense Turbine $3,786,708] $4,250,991 $4,625,507| $5,180,077 _$5,605,836| $5,998,249) Fuel Oil Expenses BU Diesels $543,241 $609,847 $663,575) $743,133 $804,213 $860,508 Total Fuel Oil Expenses $4,329,949) $4,860,838) $5,289,082 $5,923,210 $6,410,049) $6,858,757 Coal Expense $0 $0) $0 $0 $0) $0 Admin. $385,475. $416,094 $435,339 $468,782 $487,800 $501,871 Power Purchases from Bethe! Utilities $0 $0) $0 $0 $0 $0 Subtotal $5,974,644 $6,661,139) $7,199,552 $8,010,264 $8,613,775 $9,159,945 ‘SWGR System Debt Service $0 $0) $0 $0 $0 $0 SWGR O&M $62,048 $105,108) $126,233 $179,224 $202,460 $215,103 Admin. $31,024 $52,554. $63,117 $89,612: $101,230; $107,552 Subtotal $93,072 $157,661 $189,350) $268,835 $303,691 $322,655) Total Expenses $6,067,716 $6,818,800 $7,388,901 $8,279,119) $8,917,466, $9,482,600) ‘8. Power Cost Avg. Busbar Cost/kwh - Bethel $0.127 $0.132 $0.136) $0.141 $0.146) $0.151 Avg. Cost $/kwh SWGR System $0.028 $0.029) $0.029 $0.030 $0.031 $0.032 Avg. Busbar Cost/kwh - Villages $0.155 $0.160) ‘$0.166) $0.172 $0.177 $0.183 B.1 Additional Non-Fuel Expenses Villages $0.080) $0.082 $0.085) $0.087 $0.090 $0.093 B.2 Average Cost to Village Consumer $0.235) $0.243) $0.251 $0.259 $0.267 $0.276 16. Waste Heat Recovery _ Available Waste Heat For Sale (1,000,000 Btu) 105,120 105,120 105,120 105,120 105,120) 105,120 (Diese! Fue! Gal Equivalent) 761,739 761,739) 761,739 761,739) 761,739 761,739 Waste Heat Sales @90% Fuel Cost $980,358 $1,019,573] $1,060,355) $1,102,770) $1,146,861 $1,192,756) 17. Power Costs with Waste Heat (WH) Offset [Rate Reduction $/kwh from WH Sales $0.012 $0.012 $0.013 $0.012 $0.013 $0.013 Busbar Cost $/kwh w/ WH Offset A. Bethel $0.115) $0.119 $0.124 $0.129 $0,134. $0.138) B. Villages $0.143) $0.148 $0.153) $0.159 $0.165, $0.170) B.1 Average Cost to Village Consumer $0.223 $0.231 $0.238) $0.247, $0.255) $0.263 including Non-Fuel Expenses 8. Present Worth Costs Yr 2000 Dollars PW Factor 0.871 0.842 0.814 0.786 0.759 0.734 PW Avg. Cost/kwh. A. Bethel Busbar $/kwh $0.100) $0.101 $0.101 $0.101 $0.101 $0.101 B. Villages B.1 Village Busbar $/kwh $0.124 $0.125, $0.125) $0.125) $0.125) $0.125) B. 2 Village Avg.Cost including non fuel costsS/kwh $0.194 $0.194 $0.194 $0.194 $0.193 $0.193 IPW_Power Cost A. Bethel Busbar $4,718,068 $4,534,556 | $4,673,112 $4,843,399) $4,983,637, $5,116,093 B. Villages B.1 Village Busbar $413,333 $685,027: $800,565. $1,111,543 $1,221,200) $1,259,915 B. 2 Village Avg. Cost including non-fuel costs $645,336) $1,065,867 $1,243,794 $1,721,362 $1,688,775) $1,947,243) Accumlated PW Power Cost A Bethel $4,718,068 $9,252,625| _ $13,925,736] $18,769,135] $23,752,772] $28,868,865) B. Villages B.1_ Village Busbar $413,333) $826,667 $1,511,694 $2,312,258 $3,423,802. $4,645,002) B. 2 Village Avg Cost including non-fuel costs: $645,336) $1,711,204 $2,954,998) $4,676,359) $6,565,134 $8,512,377, C. Bethel + Villages without non-fuel Costs $5,131,402] $10,079,291] $15,437,430] $21,081,394] $27,176,574] $33,513,867 Bethel + Vill with non-fuel 405, 10,963,828 16,880,734 445,495, 317,906, 7,381,242 SWGR Bethel+8, grants 2of2 06/10/2002 Summary - Power Costs with Continued Diesel Gen. in 8 Villages 2005 1,092,066 1,129,789 1,168,135 1,246,700 $0.524 $0.542 $0.561 . $0.600 $572,668 $612,619) $655,046 $747,907 923703 956589 990035. 1058608: $0.336 $0.347 $0.359 $0.384 $310,264 $332,143 $355,368 $406,161 645651 677828 710784 779032 $0.429 $0.444 $0.458 $0.489 $277,237 $300,670 $325,742 $352,553) $381,210 1197162 1245071 1293905, 1343664 1394349: $0.345 $0.356 $0.367 $0.379 $0.391 $412,713) $442,999 $475,193 $509,404 $545,746 771282 804398 838210 872718 907922 $0.494 $0.510 $0.527 $0.544 $0.562 $380,741 $410,117 $441,443) $474,834 $510,413) 471944 499187 527141 555808, 585186 $0.402 $0.410 $0.419 $0.428 $0.438 $189,630 $204,755 $220,879 $238,064 $256,374 2660299 2751829 2844891 2939487 3035616 $0.505 $0.524 $0.543 $0.563 $0.584 $1,344,277 $1,441,767|__$1,545,487| $1,655,802] $1,773,092 685718 709568: 733810: 758444 783471 $0.289 $0.296 $0.303 $0.310 $0.318 $198,173 $209,890 $222,251 $235,290) $249,047 8,447,825 8,774,259] _ 9,106,911 9,445,788! —_ 9,790,884 $3,685,702 $3,954,960] $4,241,409] _ $4,546,054| $4,869,949) $0.436 $0.451 $0.466 $0.481 $0.497 0.871 0.842 0.814 0.786; 0.759) $3,210,247 $3,329,970] $3,450,389] _$3,573,157| _ $3,698,295 $3,210,247 $6,540,217| $9,990,605] $13,563,763] $17,262,058 Utilities at Single Phase Rates Continued Diesel8villages 1 06/10/2002 Power Costs Comparison MW Combined Cycle Turbine | _A. Bethel Busbar $/kwh B. Village Busbar Cost $/kwh Bethel Utilities Generation _A. Bethel Busbar $/kwh__ A. Saas Busbar $/kwh __B. Village Busbar Cost $/kwh B.1 Village Avg.Cost with non-fuel costs$/kwh ted PW Power Cost 10 MW Combined Cycle Turbine _ __ A Bethel $5,844,049 $11,362,912 $16,986,767 $22,714,911 $28,551,196.8260 $34,499,465.2543| $994,307 $2,628,041 $4,524,321 $6,439,611 $8,375,222.6593 $10,332,453.0461 $6,838,357 $13,990,953 $21,511,088 $29,154,522 $36,926,419.4853 $44,831,918.3003 $8,078,821 $15,863,901 $23,971,814 $32,334,991 $40,958,321 $49,846,747 _B. B. Villages $1,714,362 $4,493,541 $8,628,434 $12,816,247 $17,059,497 $21,360,660 _ C. Total $9,793,183 $20,357,442 $32,600,249 $45,151,238 $58,017,819 $71,207,407 Continued Diesel Generation(1) A. Bethel $8,078,821 $15,863,901 $23,971,814 $32,334,991 $40,958,321 $49,846,747) __B. Villages $2,276,045 $4,638,153 $7,086,884 $9,623,971 $12,251,160 $14,970,216 C. Total $10,354,866 $20,502,054 $31,058,699 $41,958,962 $53,209,481 $64,816,963} Accumulated Savings Nuvista versus Bethel Utilities Generation $2,954,826| $6,366,489 $11,089,161 $15,996,716 $21,091,399 $26,375,489) Nuvista versus Continued Diesel Generation ___ $3,516,509 $6,511,101 $9,547,611 $12,804,440 $16,283,062 $19,985,045 Bethel Utilities versus Continued Diesel _ $144,612 -$1,541,550 -$3,192,276 -$4,808,337 Bethel Power Costs Bethel Utilities | 2005) 2006) 2008) 2009) | | 1. Load Requirements 43,759,422) 45,070,501) 46,400,673) 47,749,938) 49,118,295 3,500,754! 3,605,640) 3,712,054) 3,819,995) 3,929,464 47,260,176) 48,676,141) 50,112,727; 51,569,933) 53,047,759 8,300 8,549 8,801 9,057 9,316 | | | Fuel Costs per Gallon $2.30 $2.39] $2.49 $2.59 $2.69, Fuel Cost $/kwh $0.170 $0.177 $0.184 $0.192 $0.199 O&M+Admin $/kWh $0.023 $0.023 $0.024 $0.025 $0.026 Busbar Costs $0.193 $0.201 $0.208 $0.216 $0.225) Total Annual Busbar Power Cost $9,043,322) $9,676,628 | $10,349,874 | $11,065,388 | $11,825,623 Retail kwh Costs(1) Single Phase $0.289 $0.296 $0.303 $0.311 $0.318 Three Phase(2) | | $0202} $0.209) $0.217/ $0.225 $0.233 3. PW Power Costs Year $2000 Dollars | PW Factor 0.871| 0.842| 0.814/ 0.786) 0.759 PW Busbar Cost $/kwh $0.168/ $0.175) $0.182 $0.189 $0.196 PW Single Phase $/kWh $0.252 $0.258 $0.264 $0.271 $0.277 PW Three Phase eee $0.176 $0.182 $0.189 $0.196 | | | | PW Busbar Power Cost | $7,880,733) $8,147,461] $8,419,629] $8,697,295 Accumlated PW Busbar Power Cost | $7,880,733] $16,028,194] $24,447,823] $33,145,117 | $42,125,632 (1) Calculated Using Bethel Utilities Single Phase and Three Phase Tariff (2) Add $22.21/kW Demand Charge to Calculate Total Power Costs ] ] ] Bethel 1 06/10/2002 B.2. Bethel Alaska Cogeneration Project, prepared by Precision Energy Services, Inc. PES ==... BETHEL, ALASKA COGENERATION PROJECT FUEL OIL #2 — FIRED TURBINE WITH HEAT RECOVERY STEAM GENERATOR AND STEAM TURBINE APRIL, 2002 Prepared By: Precision Energy Services, Inc. Project Development Division Bethel Cogen 04 2002A1 Page | of 17 JPE re SERVICES INC. INTRODUCTION TC\LI "INTRODUCTION This report has been prepared to be used as a part of a feasibility study of a cogeneration power plant intended to be developed for the supply of electric power in the City of Bethel, Alaska. In addition, the plant will have the capability of supplying heat to local municipal buildings and hospital. The goal of this report is to provide the project developers sufficient information to identify a cogeneration option that will supply power and district heat at a cost that is competitive to that generated with the use of diesel engines. Permitting issues relating to the construction and operation of the power plant have been signaled here to make the developer aware of the possible requirements. The system that has been evaluated herein consists of a combustion turbine fired with distillate oil #2, one heat recovery steam generator, one steam turbine and one each electric generator driven by respective turbines. A system in which both turbines drive one generator is significantly more complicated; the cost advantage is very small in comparison with the degree of plant complication. The system will also include a heat exchange station that would supply hot water for heating. In the heat exchanger station saturated steam extracted from the steam turbine will condense and give off the latent heat of vaporization/condensation to heat the water circulating in the outside heating system. The system will be engineered and operated according to the latest developments in the District Heating technology being promoted by the International Energy Agency. For the evaluations included in this Report, four combustion turbines were considered: General Electric GE10, Alstom Power Tempest Generator Package, Solar Turbine Taurus 70 and Kawasaki GPB60/70 DLE. Following evaluation of the materials received from vendor, the latter was eliminated from further evaluation due to lack of sufficient data. All turbines represent state of art in liquid fuel turbine combustion technology. Utilization in this project of the combined cycle cogeneration arrangement with partial heat supplied to a local district heating system enables the facility to achieve thermal efficiencies in the range of 53 to 60%, which is practically not achievable by a diesel engine-based generating plant. The heat rate (thermal input in fuel to produce one kW of electric or equivalent power) of this plant will be in the range of 6,000 to 7,230 Btu/kW. Also the financial results of the cogeneration plant indicate a positive feasibility. The cost of generating power is in the range of $93 to $112 per MW-hr depending on the length of debt financing period. Bethel Cogen 04 2002A1 Page 2 of 17 PRECISION ENERGY SERVICES INC. 1. INPUT / OUTPUT DATA The following table summarizes the Input information (required power and heat and other data) as well as output data as provided by three vendors. NA data not available NAp data not applicable NI Not included PBO _ To be provided by others (than the main vendor) = Data provided by vendor; all other data — calculated or from generally available sources as’d = assumed Table 1, Input / Output Data 1 |Fueldata #2 Distillate oil, net HV Btu/Ib 17,855 1.1 Btu/gal 128,869 1.2 | Density Ib/gal 7.22 Vendor / System Solar Alstom GE 2 | Required electric output, net KW 10,000 21 Parasitic power - turbine (fuel pump, KW 22| NA, as’d 50 | 2.2 | Parasitic power - steam system KW 278 Required electric output, gross KW 10,300 10,328 10,338 [3 [Cr Turbine ri 3.1 | CT turbine output KW * 7,310 * 7,575 * 10,120 Turbine heat rate Btu/kW-hr 10,260 * * ;. * 3.2 | Heat input Btu/hr 75,000,600] 88,376,000 95,611,000 3.3 | Fuel input Ib/hr 4,201 * 4,856 * 5,253 3.4 gph 582 673 728 3.5 |Combustion air supply Ib/hr 207,074 240,544 290,945 3.6 ees = nepal enn eneed 5 TERI 24,941,720] 25,845,900] 34,529,440 3.7 | Heat content in combustion gases Btu/hr 50,058,880 58,410,825 61,081,560 Heat recovery steam generator | 4 (HRSG) PBO Included PBO 4.1 |Products of combustion lb/hr * 211,274] * 236,520 * 296,300 4.2 | Turbine exhaust temperature °F 960} * 992 * 968 4.3. | Heat losses in system (convection, =f yar 1,498,800] 1,748,900 1,828,800 radiant, boiler blowdown, ...) | 4.4 |HRSG system exhaust temperature °F 265 * 322 * 751 4.5 | Heat losses with flue gas in exhaust Btu/hr 8,801,500} 14,281,200 51,081,600 Bethel Cogen 04 2002A1 Page 3 of 17 IDES =: — SEHVICES INC. 4.6 | Heat available for steam generation — 39,758, 42,380,750 Not required 4.7 |Superheated steam parameters * 754 Table 1, continued Vendor / System Solar Alstom pg a5 | Soperhosted sieam goncrafiod 31514)» 3721| 0 = Additional duct firing | _—_|_Reaited|_Not requires Not rented DH + DA steam flow 14,733 al ass Nal Power Generation in both Cycles Power generation with DH and DA 5:3 kW 800 780 NA 5.4 Power generation in condensing cycle kw 1,715 2,338 NA 55 Power generation with condensing & kw 2,515 * 3.118 * 3,632 extraction steam 5.6 Total power generation kw 9,826 * 10,693 * 10,120 5.7 Power generation shortage kW 474 0 218 5.8 Equivalent amount of superheated steam Lb/hr 4,640 NAp NAp required Equivalent NET thermal input required 5.9 fe aidtitional firing Btu/hr 5,920,310 NAp NAp Equivalent GROSS thermal input 5-10 quired in additional firing — i NAB NAP 5.11 Equivalent fuel input for duct burning Lb/hr 516 NAp NAp 5:12 gal/hr 72 NAp NAp 6 Total fuel demand gal/hr 653 673 742 gj Dmiriothesting (DE) energy (includes pein 10,000,000 10,000,000 10,000,000 95% efficiency) 6.2 Converted to equivalent power units KW-hr 2,930 2,930 2,930 6.3 Total equivalent power kW-hr/hr 13,230 13,258 13,268 7 Performance 7.1 Heat rate I on electric power generation Btu/kW-hr 8,000 8,160 9,250 7.2 Heat rate II on equivalent power BtwkW-hr 6,230 6,360 7,210 73 Heat rate ill on electric power generation Btu/kW-hr 10,260 11,120 9,450 in CT turbine 7.4 Plant efficiency I on electric power 44.7% 43.3% 36.1% 7.5 Plant efficiency II on equivalent power 54.8% 53.7% 47.4% 6a Total fuel demand per day gal/day 15,672 16,152 17,808 Bethel Cogen 04 2002A1 Page 4 of 17 PRECISION Y SERVICES INC. 6b Total fuel demand for 120 days bbl 44,780 46,150 50,880 The fuel to be utilized at the plant is #2 Distillate oil as per ASTM Standard D396. Explanations: Heat rate I Total heat input; line 3.2 + 5.10 divided by required power output, line 2.3 Heat rate II Total heat input; line 3.2 + 5.10 divided by equivalent power output, line 6.3 Heat rate II Heat input in turbine; line 3.2 divided by turbine power output, line 6.3 Equivalent power output includes electric power output of the combustion and steam turbines, and thermal power supplied to local heating system converted into electric power units by dividing the heat input (10,000,000 Btu/hr) by the conversion factor of 3412 Btu/kW-hr. Plant efficiency I Total power generation without co-firing, line 5.6 multiplied by power-to-energy conversion factor of 3412 Btu/kW-hr divided by energy input without cofiring. Plant efficiency I Total equivalent power generation with co-firing, line 6.3 multiplied-by-power to energy conversion factor of 3412 Btu/kW-hr divided by total energy input with cofiring. Remark regarding the system proposed by GE The GE 10 DLE turbine will generate continuously 14.5 MW at 100% turbine capacity. The data provided in the above table are for 60% capacity equal 10,120 kW. If this turbine is operated in the simple, single CT generating cycle, it can produce net 10 MW as required. A small portion of the heat contained in the flue gas will be exchanged in a water heater to produce the heating medium for the local heating purposes. In order to facilitate cogeneration, the turbine would have to be run at about 50% capacity, which results in an overpriced machine and reduced generation efficiency. A comparison sheet is attached showing the required price of electric power for the Solar turbine-based system compared to pricing required if the system included the GE 10 DLE turbine-generator. See section: Financial Analysis. Bethel Cogen 04 2002A1 Page 5 of 17 RES PRECISION ENERGY SERVICES INC. Description of the Power Plant TC\L1 "SUMMARY AND CONCLUSIONS The Power Plant will include the following systems: Fuel receiving and storage tanks. One liquid fuel combustion turbine with directly driven electric generator. One heat recovery steam generator including economizer with ducting and exhaust stack. Steam turbine with directly driven electric generator. Steam condenser with cooling tower and cooling water circulating pumps. Switch gear and substation. Feed water chemical treatment, deaerator and pumps. Instrumentation and controls, central control room and motor control center. earn annrpAwn = Maintenance shop with tools. 10. The plant will be housed in appropriate buildings. The buildings will also include locker and lunchroom facilities. Fuel Receiving and Storage The plant will consume estimated 16,800 gallons of fuel per day. The fuel receiving and storage system will be capable of storing fuel supply for 2 months operations; that is 1,000,000 gallons. The fuel will be stored in appropriate thermally insulated tanks. The tanks will be winterized, as necessary. The fuel receiving and storage system will be equipped with fuel pumping equipment for unloading from ships and separate pumps for the delivery of the fuel to the combustion turbine and other burners at the plant. All fuel piping will be thermally insulated. The system will include also a vapor recovery and fuel loading hermetization system for prevention of emissions of fuel vapors and recovering those. Combustion Turbine For the purposes of this study, budget type proposals were requested from major manufacturers/suppliers of small power combustion turbines. Those include: - ALSTOM Power - Solar Turbines - GE Aero Energy Products - Kawasaki Gas Turbines Following initial evaluation of the materials received from vendors, the Kawasaki options was eliminated from further evaluation due to lack of sufficient data. Also, the proposed turbine is too small in comparison to the required performance. The steam cycle in the system with the Kawasaki turbine would require too much additional firing in a duct burner. Bethel Cogen 04 2002A1 Page 6 of 17 PRES Firctone Information packages of the respective CT turbines are attached to herein. A summary of important data is presented in the Input/Output Data Table (the I/O Table). The CT turbines are supplied by the respective vendors with the scope listed in the following summary. Some minor differences between suppliers do exist, however, we have done our best to reduce the differences to an absolute minimum that would not impact the performance of the system. Engine Core Engine Instrumentation Air inlet casing temperature thermocouples Compression section discharge temperature thermocouples Low pressure turbine exhaust outlet temperature thermocouples Engine bearing temperature monitoring Rotor speed probe Accelerometer type vibration probe on engine casing Non-contacting vibration probes in turbine radial and thrust bearings Key phasor Turbine compressor discharge pressure transmitter Vadettles: fabricated steel construction, designed for multi-point mounting to carry the gas turbine, gearbox, generator, and auxiliaries; including an integral lube oil tank constructed from carbon steel, and gland plate in underbase to facilitate cabling for electrical devices Lube Oil System mounted on a skid. Integral lube oil system serving the turbine, gearbox and generator. Main pump, gearbox driven Auxiliary lube oil pump with AC motor drive Emergency lube oil pump with DC motor On-skid lube oil piping, stainless steel. Lube oil pressure transmitter and switch Lube oil supply temperature thermocouple and switch Lube oil tank temperature thermocouple Lube oil tank low level switch and annunciation One (1) lube oil tank immersion heater Duplex-type 10 micron lube oil filter, fitted with differential pressure switch. Lube Oil Breather System with low pressure oil mist eliminator breather system constructed of carbon steel for oil mist reduction Oil Cooler with simplex fin-fan lube oil cooler suitable for an ambient temperature up to 95°F Non-return valves for lube oil cooler pipe work. Engine Auxiliaries Turbine compressor cleaning system for hot and cold water wash Aluminum instrument bodies Identification and warning labels Stainless steel on-skid pipe work with stainless steel compression fittings Breather from lube oil tank and engine casing, piped to the roof of the acoustic enclosure Start System with variable frequency drive starting system DLE Liquid Fuel System Liquid fuel pump, AC motor driven Duplex type, 10 micron, liquid fuel filter complete with differential pressure transmitter On-skid fuel piping in stainless steel downstream of filter Shut-off valves Liquid fuel grounding Bethel Cogen 04 2002A1 Page 7 of 17 IDES 2: — SERVICES INC. - Independent control of primary, secondary and tertiary liquid fuel flows - Off-skid shut off and thermal relief valves supplied loose Air Intake System comprised of: Pulse-type self-cleaning combustion air intake filter, constructed of painted carbon steel, with simple support structure and access ladder - Combustion air intake silencer, constructed from painted carbon steel, designed for overall sound attenuation to 85 dB(A) at 3 ft (1m) measured at 5 ft (1.5 m) above grade - Expansion joint Transition duct Extent System Diffuser constructed from stainless steel Acoustic Enclosure fitted over the turbine, gearbox and generator, bolted to the underbase, for average sound attenuation to 85dB(A) SPL at 3ft measured at 5ft (1.5m) above grade; with internal lighting, carbon steel construction with doors and removable side panels for personnel/maintenance access. Ventilation System of the Enclosure with ventilation inlet and outlet dampers and inlet and outlet silencers, constructed of painted carbon steel, designed for an overall noise level of 85dB(A) SPL at 3ft, measured at 5 ft above grade, and Simplex AC electric motor driven ventilation fan designed for Class 1 Division 2 Group D area classification, and a maximum for ambient temperature up to 95°F (35°C) and ventilation air flow detector Fire and Gas System - Four (4) ultra-violet flame detectors - Two (2) heat detectors - Two (2) gas detectors - Twin shot CO, fire protection system with provision for weighing the CO2 bottles to monitor charge - Audible and visible alarms for extinguishant release - Suitable for Class 1 Division 2 Group D area classification Gearbox System - Epicyclic speed reducing gearbox with an output shaft speed of 1800 rpm with accelerometer vibration probe mounted on the gearbox casing; designed for turbine rated core - Output Coupling - dry diaphragm coupling with torque-limiting device between gearbox and AC generator - Coupling Guard constructed from non-sparking material AC Generator and Electrical Equipment - 1800 rpm, 13.8 kV, 3 phase, 4 wire, 4 pole, 60 Hz, 0.8 power factor, salient pole brush-less AC generator, nominally rated to match the turbine output at 59°F (15°C) - Open ventilated - Generator bearing temperature detectors - Class ’F’ insulation with class °F’ total temperatures - Stainless steel junction boxes - Classified for a non-hazardous area Control System The basic equipment package is supplied with a free-standing control panel suitable for mounting in an indoor, non-hazardous area. The control system features an integrated electronic fuel management system with a PLC based programmable sequencer, vibration monitor, digital meter, digital generator protective relay module and a desktop computer. Alarm and shutdown events are displayed on the HMI automatically. An Ethernet TCP/IP EGD or RS485 Modbus Port is provided to transmit unit conditions (status, pressures, temperature, etc.) to the customer's distributed control system. A printer can be furnished to provide hard copy records. Power for the control panel is provided by a dedicated 24V DC lead acid battery system with dual 100% capacity chargers. Bethel Cogen 04 2002A1 Page 8 of 17 PRECISION ENERGY SERVICES INC. The control system includes the following: - Turbine sequencing and protection - Fault monitoring - Intelligent display - Annunciation - Gas turbine speed control - Temperature monitoring - Standard turbine casing vibration monitoring - Generator bearing temperature monitoring - Monitoring of accelerometer on gearbox - Transient logging package for fast data logging - Interlocks for standard fire and gas monitor - Automatic voltage regulator - Automatic and manual synchronizing facility with check synchronizer - Generator metering equipment and electrical protection Electrical Accessories - All on-package electrical devices to be Class 1 Division 2 Group D area classification - All on-package control cabling - Stainless steel junction boxes, located on external surface of gas turbine generator package - Galvanized carbon steel cable tray - Integral grounding protection - Emergency ’stop’ push-button on turbine underbase - Battery Cabinet constructed of carbon steel, located off main skid Heat Recovery Steam Generator For this study three quotes of HRSG were obtained: - Deltak Boilers (supplied by Alstom Power) - ABCO Boilers - ENERCOR The ABCO or ENERCOR boilers should be procured separately; neither GE nor Solar Turbines included in their proposals the HRSG. The Deltak boiler should be procured through Alstom. All three companies specialize in this type of steam generation systems. Our experience with ABCO and Deltak indicate that the quality of their products and professionalism of their engineering is between the highest in the industry. In the case of the Solar Turbines and Alstom Power CT turbines, additional firing is needed. The I/O Table does not show for Alstom the duct firing data because it is included in the information supplied by Alstom for the turbine system. The HRSG system will include: - Expansion joint to HRSG - Transition duct, internally insulated - Firing duct with in-duct burner - Deltak boiler with built-in removable superheater - Economizer - Walkways & Platforms Bethel Cogen 04 2002A1 Page 9 of 17 PRES Firctone - Trim to ASME Section 1 Jurisdiction - HRSG Control module with outputs supplied to the Central Control Processor - Interconnecting piping - Single Blade Diverter - Outlet and bypass stack & associated structure - Valves and Controls - Boiler feedwater regulator - Water column assembly with gauge glass, electrical lock-out and auxiliary switches for high and low level alarms, and high and low level shut downs. - Three element feedwater control system including water level transmitter, steam flow element and water flow element. - Water and steam pressure gauges - Water and steam thermometers - Exhaust gas temperature and pressure indicators - Main steam non-return valve - Main steam stop valve - Feedwater stop-check valve - Continuous blow-down tandem valve set - Intermittent Blow-off tandem valve set - Water column and gauge drain valves - Superheater drain and vent valves - Economizer drain and vent valves - Chemical feed valve - Safety valves per ASME Code c/w silencers. Steam Turbine and Generator System The Steam Turbine and Generator system will be included in the Power Plant typically consisting of: - Turbine unit with condensing steam exhaust and one back pressure steam extraction outlet with non-return valves for district heating and de-aerator. The unit is provided with axial exhaust orientation, for direct connection to the condenser flange. Emergency stop valve and non-return valves are included as required. - Required piping, insulation blankets, sheet metal lagging - Generator, 13.8 kV, 60 Hz, 3600 rpm, 0.8 PF with brush-less excitation and coolers sized for water temperature 85°F. Generator shaft is monitored for vibrations and grounded. RTDs are provided in each phase windings and in air ducts and bearings. Water leak detection is provided. Coupling flange is integrally forged. - The CT Lubricating Oil System will supply all lubricating oil needs of the steam turbine. It will include interconnecting piping and oil coolers sized for water temperature 85°F. - Speed Reduction gear; parallel shaft design in compliance with AGMA 421.06. Shaft vibration is monitored. RTDs are installed in bearings. - Complete stand-alone digital control system handling all required turbine and generator controls (closed and open loop) and monitoring instrumentation (power output, pressures, temperatures, vibrations, etc.) of the steam turbine and generator unit. The control system includes a coordinating controller plus separate control units for the turbine governor function, steam turbine safety trip functions and generator voltage regulator functions. - Generator protection relays, if required. All man-machine interface, as well as all measurements, status and alarm displays are handled from the Plant operator station with color monitor, keyboard Bethel Cogen 04 2002A1 Page 10 of 17 IPES ric me and trackball, supported by an event and alarm printer. - Unit is built for indoor installation with noise attenuation to 85 dBA. Steam surface condenser with two feedwater circulating, liquid ring vacuum pumps. Each pump at 100% capacity. The condenser is built of 304L stainless steel tubing and tubesheets and coal tar epoxy coated water boxes. The surface condenser quote was provided by Alstom Power. Cooling tower — two cell; fiberglass structure, stainless steel connecting hardware, heavy duty PVC film pack fill, two fans with drive, fire retardant FRP fan cylinders for velocity recovery. The cooling tower quote was provided by Psychrometric Systems, Inc. Feed water chemical treatment and deaerator. Air pollution control system Due to the character of the project, the air pollution control system will be minimal. Two types of pollutants from the plant require discussion because they may possibly present a control requirement: - Carbon monoxide (CO) and Volatile Organic Compounds (VOC) - Nitrogen oxides (NOx) Combustible CO and VOC are generated in the turbine’s combustion chamber as intermediate products of incomplete combustion. At sufficient residence time, they convert further to final products of combustion — CO, and H;0. Due to extremely short residence time in the turbines’ combustion volume or quenching caused by entering cooling air, the products of incomplete combustion escape the combustion zone. The same conditions that bring about generation of excessive CO and VOC are also responsible for high NOx generation rates. The diffusion flame in the combustion zone of a CT turbine, resulting from mixing there of the fuel and air, is highly non-uniform operating over a broad range of temperatures between 2000 and 4000°F. In such conditions NOx is created because of the high temperatures and uneven temperature distribution that tends to stabilize the products of reactions between nitrogen and oxygen. At high turbine loads the NOx generation increases. A significant factor in this process is also the use of liquid fuel, which has to be finely atomized to promote better combustion. Solar Turbines developed a process/system SoLoNOx, which reduces both types of pollutants. The fuel injector of the SoLoNOx system includes a pre-mix duct where the fuel is injected into a swirling air stream. This produces a well pre-mixed fuel air mixture that burns with a uniform flame pattern at about 2800°F. Formation of NOx is strongly impeded due to the absence of high reaction temperature zones. Also CO and VOC emissions are reduced due to sufficiently high temperature and very good premixing of the components. The GE-10 turbine will be supplied with the XONON technology, which will bring NOx emission levels of the liquid fuel application to acceptable levels without steam or water injection. The main components of this combustion system are the pre-burner, the main fuel injector, the catalytic reactor, and the post-catalytic reaction liner. The CO and VOC pollutants will be also controlled by additional combustion with a duct burner with sufficient residence time (min. 0.6 seconds) provided by the duct to the heat recovery steam generator, where Bethel Cogen 04 2002A1 Page 11 of 17 IDE ao senvices £5 mc. both the heat remaining in the combustion gases exiting the CT turbine and the heat added in the duct burner will be recovered for steam raising. The Alaska Department of Environmental Conservation (Janet 907 465-5122) determines allowable NOx emissions based on the turbine’s heat rate using the following formula for a CT turbine installation at total heat release in excess of 10 MM Btu/hr: % vol. = 0.015 x 14.4 /kJ/W-hr ppm vol. = 0.216 x 10,000 / (Heat rate [Btu/k W-hr] x 1.055/1000) The respective numbers for expected emissions are presented in the following table: Table 2, NOx generation rates calculated using Alaska DEC method Solar Alstom GE Btu/ Btu/ Btu/ kW-hr Ppm vol. kW-hr Ppm vol. kW-hr Ppm vol. Heat rate I on electric power generation 7,690 266 = 8,560 239 = 9,250 221 Heat rate II on equivalent power 5,990 342 = 6,410 319 5,730 357 Heat rate III on electric power generation in CT turbine 10,260 200 = ‘11,190 183 9,450 217 Heat rate on power and DH required 5,990 342 6,680 307 ~—s_ 7,230 283 The values in the column titled ppm vol. are very high, especially when compared to the actual capabilities of modern CT turbines. The following table shows values based on the NSPS standard of 0.15 Ib of NOx per million Btu (MM Btu). Table 3, NOx generation rates using NSPS Standard Solar Alstom GE lb/hr 1 13 14 SCFH NOx | 93 109 118 SCFH flue [ 2,780,000] 3,275,000| _ 3,958,000 Ppm vol. 33 33 30 Ppm vol. corrected to 11% O> 50 | 50] 39 Basically, the State of Alaska requires application of BACT (Best Available Control Technology). The state will require information from the CT turbine manufacturer to determine that the turbine to be installed at the site in Alaska is state of art technology. As a result, we expect that the State will not require the application of any additional NOx and CO control means. Instrumentation and controls, central control room and motor control center The Power Plant will be equipped with all instrumentation and controls necessary for trouble-free operation of the Plant. The controls and instrumentation are listed above with the respective equipment systems. The CCR (central control room) will include an operator station with color monitor, keyboard, track ball and event and alarm printers. A motor contro] center for the plant will be provided in a separate room of the main building. Bethel Cogen 04 2002A1 Page 12 of 17 IDES 2: —— enrVICES INC. The Control philosophy of the system is such that the Cogeneration Plant should operate automatically requiring very little operator input. The input shall be required only in off-spec or emergency situations. At normal operations, the system operates based on inputs from the various temperature, pressure, flow and other measuring devices. Occasional intervention of the operator will be required to set operating conditions if these have to be changed; for instance: setting changes of the local heating system as a result of significant weather changes, changes of turbine settings as a result of long-term (longer than 24 hours) change in power demand, and so on. Local Heating System The plant will include provision for connecting to a local heating system. It will include a heat exchanger for heating water circulating between the plant and the heat receivers - the local hospital, school and municipal buildings. The circulating water will be heated partially with heat of condensation in the steam turbine’s condenser and partially with extracted steam. At the maximum demand for heat, the plant will supply to the heating system an equivalent of 12 MM Btu/hr. PES has experience in engineering heat exchanger stations for district heating systems. The piping system to the heat receivers is not included in the Power Plant cost. Bethel Cogen 04 2002A1 Page 13 of 17 PRES Friston Table 4, Feasibility Analysis. Input Data see Feasibility Evaluation on the following pages spreadsheets The feasibility analysis is based on Solar Turbines supplies. Table 5, Feasibility Analysis. Output Data _—see Feasibility Evaluation on the following pages spreadsheets Table 6, Simplified Feasibility Analysis of Diesel-based Generation Plant 10 MW net output see Feasibility Evaluation on the following pages spreadsheets Bethel Cogen 04 2002A1 Page 14 of 17 PRECISION ENERGY SERVICES INC. Bethel Cogen 04 2002A1 BETHEL, ALASKA COGENERATION PROJECT FINANCIAL ANALYSIS APRIL, 2002 Prepared By: Precision Energy Services, Inc. Project Development Division Page 16 of 17 IDES == aoe SERVICES INC. Discussion The estimation of the capital cost is presented on the attached spreadsheet. The capital cost includes 2 fuel tanks with 25,000 gallons each storage capacity, which is sufficient for about80 hours. Additional fuel storage for annual requirements is being evaluated by others. The feasibility analyses for 10 and 15 year debt financing periods show expenses and revenue flow during years 1 through 3 followed by years 11 and 12, and 16 and 17, respectively; the last two columns include data for the years when the operating cost is burdened by the cost of borrowing money and principal repayment. In the years 4 through 10, of the 10-year financing case and 4 through 15 of the 15 year financing case, the financials are exactly the same as in the second and third years. For the first year we assumed plant availability to be 85%, which accounts for first year operational challenges: running-in, debugging, operator training and similar. In the evaluation with 20 year financing, all columns except the first are similar. Last two columns of the 10 and 15 year debt financing options show the financials after the loan had been paid off. Instead of calculating the rate of return on the investment (IRR), we have made an assumption that the plant owner/operator should make a 20% profit before taxes. Based on this, the minimum required sale price for electric power has been calculated. Another assumption is inclusion of the sale of energy for local heating at cost of fuel and 25% margin only. The resulting price of 1 MWe is $111.3 and 103.3 in the years when the debt financing is being paid off in the 10 and 15 year financing options and $98.2 and $93.3, respectively, in the following years. If the revenue from (and expense on additional fuel for) local heating is not taken into account, the price of 1 MWe is $115 ($117 in the first year) and $102, respectively. In the 20 year financing option the price per MWe is constant (except for the first year) at $101.8. The feasibility evaluation includes also, for comparison, a simplified feasibility analysis of a diesel engine- based generation plant with 10 MWe net output. For simplicity, the capital cost of the diesel engine based generation plant was assumed to be 50% of the cogeneration plant. The comparison shows a clear advantage of the cogeneration plant; a difference of $25 per MWe in the first 10 and 15 years and $30 in the remaining years; practically a 25% cost advantage. Even if local heating is not supplied, the price difference is still significant. The impact of the capital cost on the required price is minimal. First, the change of the capital cost changes the required price ($/MW-hr) only in the first 10 years (during the period of repaying the loan). Afterwards the required price is not affected. Reduction of the capital cost by $1.5 million (17%) results in a change of the required price of $7.00. The largest impact on the price per MWe has the cost of fuel, which is proportional to the power plant output. As shown in Table 4, the fuel cost is very high, $10.30 per million Btu. Bethel Cogen 04 2002A1 Page 17 of 17 1 |Fuel data, #2 Distillate oil, net HV |Btu/lb 17,855 44 |Btu/gal 128,869 1.2 |Density |ib/gal 7.22 | Solar Alstom GE 2 |Required electric output, net ikw 140,000 2.1 |Parasitic power - turbine (fuel pump, ...) [kw 22 NA, as'd 50) 2.2 |Parasitic power - steam system ikw 278 2.3 [Required electric output, gross ikw 10,300 10,328] 10,338] 3 |CT turbine output (all outputs at 59°F and sea level) (kW 7,310 7,575) 10,120} 3.1 | Turbine heat rate |Btu/kW-hr 10,260 11,123) 9 3.2 |Heat input |Btu/hr 75,000,600 84,256,725 95,611, 3.3 | Fuel oil input (lb/hr 4,201 4 5, 3.4 [gph 582 673 742 3.5 |Combustion air supply {Ib/nr 207,073 240,544) 290, 3.6 |Turbine output converted to thermal units |Btu/hr 24,941,720 25,845,900} — 34,529,; 3.7 |Heat content in combustion gases |Btu/hr 50,058,880 58,410,825 61,081,560 3.8 |Heat losses in system (convection, radiant) |Btu/hr 1,499,600 1,749,800) 1,829, 4 |Heat recovery steam generator (HRSG) | PBO Included) NI/NR'd 4.1 |Products of combustion (exhaust, flue gas) |Ib/hr 211,274 236,520 296,300} 4.2 [Turbine exhaust temperature °F 913 992) 968] 4.3 |HRSG system exhaust temperature (GE = output of HW heat exchanger) °F 265 322) 751 4.4 |Heat losses with flue gas at flue gas temperature |Btu/hr 8,801,500 14,281,177 51,081,560) 4.5 |Heat available for steam generation |Btu/hr 39,757,780 42,379,850 8,170,200 4.6 |Superheated steam generation {lb/hr 31,514 37,211 4.7 |Superheated steam properties 700°F, 600# | 754°F, 620# | 5 |Additional firing | 5.1 |DH + DA steam flow |Ib>ar 14,733 14,495) Not required| 5.2 |Power generation with DH and DA steam /kw 800 790 Nal 5.3 |Power generation in condensing cycle ikw 1,715 T 2,322 NA| 5.4 |Power generation with condensing & extraction steam |kw 2,516 3,112) NA\ 5.5 |Total power generation possible without co-firing |kw 9,826 10,687 10,120 5.6 |Power generation shortage _ ikw 474 0 (218 5.7 [Equivalent amount of superheated steam required liom 4,641 0 ‘Ol 5.8 |Equivalent NET thermal input required in additional firing |Btu/hr 5,921,598 0} Oo 5.9 |Equivaient GROSS thermal input required in additional firing \Btu/hr 7,376,062 0) oO 5.10 |Equivalent fuel input for duct burning {Ib/nr 516 0 oO 5.11 = __\gavhr 72 0 0 5.12 |Totalfuel input [gar 654 673 742 | __6 [Energy balance and efficiencies 6.1 |District heating energy (includes 95% efficiency)(included in balance) |Btu/hr 10,000,000 10,000,000 10,000,000} 6.2 |Converted to equivalent power units |kW-hr 2,930 2,930 2,930) |” 63 [Total equivalent power IkW-hrihr | 13,230 13,258 13,268 6.4 |Heat rate | on electric power generation [Btu/kW-hr | 8,000 8,160 9,250 6.5 |Heat rate I! on equivalent power |Btu/kW-hr 6,230 6,360 7,210 6.6 |Heat rate II! on electric power generation in CT |Btu/kW-hr 10,260 11,120 9,450 6.7 |Plant efficiency | on electric power 44.7% 43.3% 36.1% 68 [Plant efficiency || on equivalent power Seta ad oaleclncttnt bd 54.8%| 53.7% 47.4% | |Heat rate | on electric power generation |= total heat input (line 3.2 + 5.9) / power output (line 2.3) [Heat rate Il on equivalent power at input (line 3.2 + 5.9) / equivalent power output |Heat rate III on electric power generation in CT |= heat input in CT (line 3.2) / power output (line 2.3) |= electric power output without co-firing (line 5.5) x 3412 |Btu/kWh / heat input (line 3.2) CT Plant efficiency | on electric power FO2 Feasibility EngSum 07/06/2002 |= total electric power output without co-firing (line 6.3) x 3412 ipetal phen efmorency,tl.on equivelen: Rowe | BtukWh / total heat input (line 3.2 + 5.9 FO2 Feasibility! EngSum 07/06/2002 BETHEL 10 MW COGENERATION PLANT FINANCIAL SUMMARY GENERAL ELECTRIC BASED PRICING Including local heating system Capital cost 7,121,746 |Financed 75% at 6.25% interest rate 10 year financing 15 year financing 20 year financing With P+I payments | W/O P+l payments | With P+I payments | W/O P+I payments | With P+! payments Operating cost, average, first year NI 9,002,943 9,002,943 9,002,943 9,002,943 9,002,943 P+] payments 734,290 836,887 475,175 Total expenses 9,737,233 | __ 9,002,943 9,839,831 9,002,943 9,478,118 Required revenue over expenses ; 20%| 1,947,447 ‘1,800,589 1,967,966] ‘1,800,589 | 1,895,624 Revenue from sale of heat at cost of fuel + 25% 25% 1,325,657 1,325,657 1,325,657 1,325,657 1,325,657 Total required revenue 10,359,023 9,477,875 10,482,140 9,477,875 10,048,085 Power generated for sale 83,220 83,220 83,220 83,220 83,220 Required power sale price 124.48 113.89 125.96 113.89 120.74 [Without local heating system Capital cost 6,905,746 [Financed 75% at 6.25% Interest rate 10 year financing 15 year financing 20 year financing With P+ payments W/O P+ payments With P+! payments W/O P+l payments With P+! payments Operating cost, average, first year NI 9,002,943 9,002,943 9,002,943 9,002,943 9,002,943 P+! payments 712,061 542,021 460,763 Total expenses 9,715,004 9,002,943 9,544,964 9,002,943 9,463,706 Required revenue over expenses 1,943,001 1,800,589 1,908,993 1,800,589 1,892,741 Revenue from sale of heat at cost of fuel + 25% Q 0 Q 0 0 Total required revenue 11,658,005 10,803,532 11,453,957 10,803,532 11,356,448 Power generated for sale Required power sale price 83,220 129.82 83,220 | 137.63 83,220 129.82 83,220 136.46 Comparable power price with diesel generation FO2 Feasibility! SumGE 107.32 112.30 107.32 111.55 07/06/2002 BETHEL 10 MW COGENERATION PLANT FINANCIAL SUMMARY SOLAR TURBINE BASED PRICING FO2 Feasibility1, SumSOL Including local heating system Capital cost 8,791,528 [Financed 75% at 6.25% interest rate 10 year financing 15 year financing 20 year financing With P+I payments | W/O P+l payments | With P+l payments | W/O P+l payments | With P+! payments Operating cost, average, first year NI — | | 8.032.263] 8,032,253 | 8,032,253 8,032,253 8,032,253 P+ payments 7 906,555 690,070 586,617 Total expenses 8,938,808 8,032,253 8,722,323 8,032,253 8,618,870 Required revenue over expenses 20% 1,787,762 1,606,451 1,744,465 1,606,451 1,723,774 Revenue from sale of heat at cost of fuel + 25% 25% 1,325,657 1,325,657 1,325,657 1,325,657 1,325,657 Total required revenue 9,400,912 8,313,046 9,141,131 8,313,046 9,016,987 Power generated for sale 83,220 83,220 83,220 83,220 83,220 Required power sale price 112.96 99.89 109.84 99.89 108.35 Without localheating system | Capital cost 8,575,528 |Financed 75% at 6.25% interest rate 10 year financing 15 year financing 20 year financing With P+l payments | W/O P+I payments | With P+! payments | W/O P+l payments | With P+! payments Operating cost, average, first year NI 8,032,253 8,032,253 8,032,253 8,032,253 8,032,253 P+l payments 884,234 673,080 572,174 Total expenses 8,916,487 8,032,253 8,705,333 8,032,253 8,604,427 Required revenue over expenses 20% 1,783,297 1,606,451 1,741,067 1,606,451 1,720,885 Revenue from sale of heat at cost of fuel + 25% 25% 0 0 0 0 0 Totalrequiredrevenue §= | | 10,699,784] 9,638,703| —-10,446,399| 9,638,703 10,325,312 Power generated for sale 83,220 83,220 83,220 83,220 83,220 Required power sale price 128.57 115.82 125.53 115.82 124.07 wer price with diesel generation 113.86 107.32 112.30 107.32 111.55 07/06/2002 BETHEL ALASKA 10 MW COGENERATION PROJECT DISTILLED OIL #2 FIRED TURBINE + STEAM CYCLE FEASIBILITY EVALUATION, 20 YEAR DEBT FINANCING 1 INPUT DATA FEASIBILITY ANALYSIS BASED ON SOLAR TURBINES “4.4 [Plant Capital cost. $ 8,791,528 853,546 1.2 |Plantelectric output, net Wi. MW 10.00 |Parasitic power MW 0.30 10.30 1.3 |Steam supply to local heating system MM Btu/day 282 |At distillate fuel-fired steam generating efficiency 85% in 1.4 Operating years LL years 20 1.5 |Calendar days TH days 365 16 |Fulsupply = = gallons / day 14,748 615 1.7 |CostofFuel2002basis ss tst—~S $/ gallon 1.33 |$/MM Btu 10.29 1.8 |Loan percent : LLL LIL som | 7 tl i 1.9 Equity percent i 25.0% 1.10 |Loan amount 6,594,000 1.11 Equity amount JUL LL IE "2,197,528 an 1.12 |Loan period 20 |Power purchase at $ / MW 45 1.13 |Loan interest rate 6.25% / 4.14 |P+1 payment 586,617 7 1.15 {Principal paid at year end, average per year 329,700 1.16 |Interest average in 10 years, calculated at year end, $/year 256,917 | OUTPUT 20 year sum JV Year 1 Year 2 Year 3 Year 4 Year 5 2 Cost Availability —-> 85% 95% 95% 95% = 2.1 [Operators 2 hr/d @ average $20.00 / hr +28% burden 28% 373,760 18,688 18,688 18,688 18,688 18,688 2.2 |Utilities and Consumables 2.21 |Electric power (generate own; consumption only during outages) 32,522 4,435 1,478 1,478 1,478 1,478 2.22 |Fuel 134,919,358 6,067,802 6,781,661 6,781,661 6,781,661 6,781,661 2.22 {Additional fuel (start-up, outage) 392,622 53,539 17,846 17,846 17,846 17,846 2.23 |Consumables including water 700,000 35,000 35,000 35,000 35,000 35,000 2.3 |Maintonance cost (Eqt 5%, Bldg 2.5%, £1. 10%) | 6,253,853| 312,693 312,693 | 312693| —-312,693| 312,693 24 Insurance fee (Fire, Accident) 1,000,000 50,000 50,000 50,000 50,000 50,000 2.5 |Miscellaneous, operating reserve 5% 7,164,918 326,173 359,934 359,934 359,934 359,934 2.6 |Sub-total cost (before cost of money) ee | 4 50,837,033| 6,868,330; 7,577,300; 7,577,300} —7,:577,300 7,577,300 2.7 Cost of money (interest on debt financing, 10 year loan) 5,138,344 412,125 401,219 389,632 377,320 364,239 2.8 Principal repayment 6,594,000 174,492 185,398 196,985 209,297 222,378 FO2Tcogen 22 04 021 20y feas Page 1 of 2 07/06/2002 BETHEL ALASKA 10 MW COGENERATION PROJECT DISTILLED OIL #2 FIRED TURBINE + STEAM CYCLE FEASIBILITY EVALUATION, 20 YEAR DEBT FINANCING OUTPUT Year 1 Year 2 Year 3 Year 4 Year 5 3.0 |Balance 3.1 Total expenses 162,569,377 7,454,947 8,163,917 8,163,917 8,163,917 8,163,917 3.2 Required revenue over expenses : 32,513,875 1,490,989 1,632,783 1,632,783 1,632,783 1,632,783 3.3 |Revenue from sale of heat at cost of fuel + 25% 26,511,882 1,325,594 1,325,594 1,325,594 1,325,594 1,325,594 3.4 |Total required revenue 168,571,371 7,620,343 8,471,107 8,471,107 8,471,107 8,471,107 3.5 |Power available for sale (per year) _ MW-hr 83,220 83,220 83,220 | _83,220 3.6 _ Required price per MW-hr $/MW-hr ! 101.8 101.8 101.8 101.8 — — f 2 4.0 Diesel engine generation (no cogeneration) (for comparison) _ ened = 4.1 {Total O&M cost, except fuel (50% of cogen system) [| ; | 228,745; -228,745| 228,745 | 228,745 4.2 Fuel cost (same) 6,067,802 6,781,661 6,781,661 6,781,661 6,781,661 4.3. |Cost of money and interest repayment at CC = $4,400,000 293,575 293,575 293,575 293,575 293,575 4.4 |Total cost 6,610,414 7,303,982 7,303,982 7,303,982 7,303,982 4.5 |Required revenue over expenses 1,322,083 1,460,796 1,460,796 1,460,796 1,460,796 4.6 | Total required revenue 7,932,496 8,764,778 8,764,778 8,764,778 8,764,778 4.7 |Power available for sale (per year) with diesel generation 61,772 69,039) 69,039) 69,039 4.8 — |Required price per MW-hr (without LH) 128.4 127.0 127.0 127.0 FO2Tcogen 22 04 021 20y feas Page 2 of 2 07/06/2002 BETHEL, ALASKA, 10 MW COGENERATION PROJECT DISTILLED OIL #2 FIRED TURBINE + STEAM CYCLE CAPITAL COST SCHEDULE Designation i CT Turbine - GE10DLN | - Al Commissioning tools u | 10,220; NE _ 1.2 _|Commissioning Parts 124,000 |Quote 12,400 NI 1.3 |Startup, Site testing ee Ni NI 1.4 _|Powermanagement options Quote 17,300 incl. incl. 1.5 _|Switchgear Quote 144,900 Est 112,000 |Est 112,000 1.6 |MCC i Alstom 30,000 30,000 1.7 _|Cold climate protection Heating Not required 1.8 |BOP PM & Eng'g Solar 9,800 incl. incl. 1.9 _|Diverter, by-pass stack & structure Comp. Quote 100,000 |Alstom 100,000 |Est 100,000 1.10 |Exhaust silencer Comp. Quote 27,380 |Alstom 27,380 |Est 27,380 1.20 | Fuel tanks, insulated, w/heater Est 150,000 /Est 150,000 |Est 150,000 1.30 |Shipping Quote 61,100 |Est 75,000 |Est 95,000 1.31 |Contingency BOP 4% PES 25,379 20,680 1.32 _|Sub-total BoP PES 535,859 494,380 535,060 1.33 |Sub-Total CT TURBINE Solar 3,409,259 3,192,000 4,515,060 i 2.0 |HRSG(EV,SH,ECO) ABCO 650,000 |Deltak 625,000 |ABCO 2.1 |Shipping incl. prep forandtrucking |Est. 65,000 | _ _ | 45,000] | 2.2 Alternative Enercor 500,000 |Enercor 550,000 |Enercor 2.3 Alternative, shipping incl. prep for and trucking Est. 35,000 35,000 2.4 _|Deaerator Roth 58,804 /Roth 58,804 {Roth 58,804 2.5 _|Steam turbine Tuthill 1,175,000 |Tuthill 1,175,000 |Tuthill 1,175,000 2.5a_|Shipping turbine, switchgear, condenser, oil purifier Quote 23,500 23,500 26,000 2.6 _|Lube oil purifier system incl first lube oil fill Tuthill 20,000 20,000 20,000 2.7 _|ST Switchgear Comp. Quote 120,000 120,000 120,000 2.8 |Condenser Quote 250,000 250,000 250,000 2.9 |Water supply incl. demineralizer Est. 120,000 120,000 120,000 2.10 |Feedwater pumps (2 x 14000) + by-pass loop Quote 52,000 52,000 52,000 2.11 _|LH heat exchanger Est. 60,000 60,000 60,000 2.12 |Subtotal HR system 2,594,304 2,549,304 2,616,804 Subtotal HR system with alternative HRSG 2,414,304 2,464,304 | 2,566,804 Sub-total Equipment 6,003,563 5,741,304 7,131,864 | Sub-total Equipment with alternate HRSG 5,823,563 5,656,304 7,081,864 FO2Tcogen 22 04 021 CAPCO Page 1 of 3 07/06/2002 [| No.) Designation Total plant system BETHEL, ALASKA, 10 MW COGENERATION PROJECT DISTILLED OIL #2 FIRED TURBINE + STEAM CYCLE CAPITAL COST SCHEDULE ai Piping incl heat tracing (where needed) ee es —f a_i _ Fuel piping (tank to CT & DB) inc! drains, vents & overflow, 3.11” |block and bleed valve assembly — a 1STZS Lous ee 3.12 _|Lube oil piping CT, ST, oil cooler & conditioner 6,413 6,413 6,413 3.13 |Steam piping incl. Insulation 19,590 19,590 19,590 3.2. |Ducting incl insulation where required _ 3.21 |CT - HRSG + 2 Xjoints 17,554 17,554 17,554 3.22 _|Combustion air and ventilation air inlets NI in SoS 7,600 7,600 7,600 3.3 |Electrical 3.31 |Site grounding and lightning protection 4,500 4,500 4,500 3.32 a cleats and ducts for HV and LV cabling, or cabling 9,800 9,800 9,800 3.33 |Sensing and metering voltage transformers 1,400 1,400 1,400 Grid Failure detection equipment 3,600 3,600 3,600 3.35 Power & load management system Incl power systems study 3,500 8,500 3.36 er & materials NI above and In SoS (includes plant 74,250 74,250 74,250 3.4 |I&C NI with basic eqt or above 16,000 16,000 16,000 3.5 _|Integrated Control Panel 64,000 64,000 64,000 3.51 _|Loop diagrams 6,000 6,000 6,000 3.52 |Computer equipment not included in SoS 6,000 6,000 6,000 3.53 _ |1&C labor NI with basic eqt or above 26,100 26,100 26,100 3.6 {Civil works incl engineering 3.61 _|Buildings and structures 400,000 400,000 400,000 3.62 |Site facilities 50,000 50,000 50,000 Support structures, hangers, brackets, catwalks, ladders and 3.63 [personnel protection NI in SoS 65,000 5.000 es.000 3.64 _|Lagging of various enclosures and ducting incl test for CO2 22,000 22,000 22,000 3.65 | Foundations 85,000 85,000 85,000 Total plant systems & installations 908,082 908,082 908,082 FO2Tcogen 22 04 021 CAPCO Page 2 of 3 07/06/2002 BETHEL, ALASKA, 10 MW COGENERATION PROJECT DISTILLED OIL #2 FIRED TURBINE + STEAM CYCLE CAPITAL COST SCHEDULE No. _|Designation 0 _|Installation = = = 4.1 __|Sipping of balance of materials & equipment _ a 7 96,000} 7 _96 _ ____ 96,000 4.2 |Labor 177,000 177,000 221,250 | 4.3 _|Training 55 11,580 11,580 11,580 | 4.4 |Consumables and services 78,000 78,000 88,000 4.5 _|Travel allowance for labor and supervisory staff 28,800 28,800 28,800 _46 _|Sub-Total Installation 362,580 362,580 416,830 5.0 _|EPCM total plant 10% 727,422 701,197 845,678 I 6.0 [Contingency on p. 3 & 4 10% 727,422 701,197 845,678 7.0 _|Initial set of spares for 2 years and maintenance tools 62,458 62,458 78,073 8.0 |TOTAL PLANT COST 8,791,528 8,476,817 10,226,203 8.0a |TOTAL PLANT COST with alternative HRSG 8,611,528 8,391,817 10,176,203 8.1 |Net power output 10.30 10.33 10.34 8.2 _|Unit cost $/MW installed 853,546 820,761 989,186 8.3 _|Unit cost $/MW installed with alternative HRSG 836,071 812,531 8.4 _|Installation/contruction cost as percentage of total cost ** 37.6% 85 | WihalemaiveHRSG ss SdTSSSS~S~CS*~S ESS 8.6 _|Installation/contruction cost as percentage of total cost ** 60.2% 8.7 With alternative HRSG 62.2% Explanation of abbreviations HR Heat recovery system BoP Balance of Plant [Gee Heat recovery steam generator EPCM Engineering, procurement, construction management SH Superheater NI Not included JEV Evaporator SoS Scope of supply ECO __|Economizer is All civil & structural work included in Installation/Construction CT Combustion turbine ST Steam turbine DB Duct burner LH Local heat exchanger station FO2Tcogen 22 04 021 CAPCO Page 3 of 3 07/06/2002 Solar Turbines Incorporated Budgetary Cogeneration Plant Quotation for PES Inquiry # Inquiry # prepared by Solar Representative on May 3, 2002 This quote is provided for budgetary purposes only and does not represent a firm quote. Estimation of $/KW for selected equipment....... Item Description: Cost Gas Turbine Equipment (1) Titan 130 (T-19501)S Turbine Generator Set............... ccc. ccc cee cee eesceeeseece see eeeeeseesenes $5,100,000 Commissioning Parts, Startup, and Site Testing...................ccceeeeeeeeeeeneeeees $150,000 Electrical Equipment Basic Power Management System... eb ers weiemenerses ame not included Cost of Power Management System Options. siaafass $17,300 Switchgear and MCC (design description below)............ $144,900 Switchgear, motor control center, auxiliary power transformer, and generator grounding resistor. Switchgear and MCC are ee loose. Utility Tie-In... Suenaess weswewsviet Mhecdesdws not included Total for Electrical Equipment. $162,200 Mechanical Equipment Air COMPPeSSOM..............c0cceeee cee cee eee cee cesses cesses eee ceeceeeee cesses eee cesses eneeeeeeeenee not included Fuel Gas Compressors, none provided. not included Fuel Gas Filter/Separator. not included Heat Recovery Steam Generator....................::ccseeeeeee not included HRSG Options. none selected Diverter Vailve.......... zs not included Diverter Valve Options..... a none selected Water Treatment System............0::.cccceeceeeeeeeeeeeeeeeees not included Deaerator... nin cinsnninsBininsia nde not included Total for Heat Recovery Steam system. bic anrsnesirinilineci Camis not included 1 Condensing Steam Turbine .. not included Emissions Control Equipment... . not included Continuous Emission Monitoring System, outdoor installation. not included Gas Turbine Inlet Cooling...............0::0::seseeseeseeeeeeeeeeeeees not included Mechanical/Electrical Building. anne not included CE NE i sit ciniv end iilaen enn eno ninnincinie anedincinannnemenmans-cu's not included Miscellaneous Construction Estimate = $1,711,500 (construction is by others)... eeeeenee not included BOP Project nina & engineer — =e Equipment Oni. $8,600 Shipping... devteeeeteeeeeees M caseedtutausainaecnstutieusiese 66 $108,600 Customer Internal Costs. $0 Coie MARI CN iiss ss caxncnma ses vena keseicns ixesamnnnens LaRaennn eas a8 $0 0% Balance of Plant Contingency...................ccccceee cee cee eee eee see eeeeesee ene eeeeeeneee $0 Total for BOP Equipment (installation not included)...................0.cceeeeeeeee eee eee es $279,400 Grand Total for Turbomachinery and Balance of Plant.. $5,529,400 $394/KW Cogeneration Plant Estimated Performance Summary PES Solar Turbines Incorporated May 3, 2002 Gas Turbine: KW Gross Output @ ISO Conditions: 14,000 KW Site Ambient Temperature for Performance Analysis: 59 °F Site Elevation for Performance Analysis: 40 Ft Site Ambient Relative Humidity for Performance Analysis: 60 % Turbine Inlet Pressure Loss: 4"H,0 Turbine Outlet Pressure Loss: 4"H20 KW Gross Output @ specified site conditions: 13,613 KW Gas Compressor Power Consumption: 0 KW Turbine Auxiliary Power Consumption: 27 KW Total Auxiliary Power Consumption: 27 KW. Net Turbine Power Production: 13,586 KW Boiler: Condensate Return: 0% Steam Contributed by Gas Turbine: 0 Ibs/hr Steam Contributed by Ductburners: 0 Ibs/hr Deaerator Steam Consumption: 0 Ibs/hr Boiler Steam Flow: 0 Ibs/hr Steam Flow to Process: Steam Turbine: Steam Flow to Turbine: 0 Ibs/hr Steam Turbine KW Production: 0 KW Combined Gas Turbine and Steam Turbine Gross KW Production: 13,613 KW Chillers: Steam Flow to Chiller System: 0 Ibs/hr Tons of Refrigeration Produced: Cycle Performance (lower heating value basis): Net Turbine Heat Rate: 10,100 BTU/KW Gross Plant Heat Rate (Process steam or Tons converted to equivalent KW): 10,100 BTU/KW Overall Cycle Thermal Efficiency: 33.8 % Purpa Calculations (for reference only): Useful Thermal Output: 0.0 % Total Efficiency Standard: Solar Turbines Incorporated PES Proposed P&ID Schematic To Stack Natural Gas 915°F .0 MMBtu/hr j Lower Heating Value Basis Natural Gas 137.3 MMBtu/hr | I 150 psig/Sat. Process Steam 100 psig Ductburner |. 375 psig Gas Compressor Filter/Separator H (Not Included) (Not Included) \ 212°F Condensate \ Exhaust Retum - 60% No. 2 Oil \( 390,272 Ib/hr -0 MMBtu/hr \, 915°F Air J [— (1) Titan 130 (T-19501)S 59.0°F Evap. Cooler ISO Rating - 14,000 kW (Not Included) Note: For Estimating Purposes only. For Guaranteed Performance, see your Solar Turbines Representative. Solar Turbines Oe md T ITAN 130 Gas Turbine Generator Set Nominal Performance* Output Power, kWe 13 500 ISO: 15°C (59°F), sea level Heat Rate, kJ/kWe-hr 10 810 (Btu/kWe-hr) (10,250) Exhaust Flow, kg/hr 179 770 (Ib/hr) (396,390) Exhaust Temperature, °C 489 Ch) (913) * No inlet or exhaust losses Relative humidity 60% Natural gas fuel with LHV = 31.5 to 43.3 MJ/nm* (800 to 1100 Btu/scf) Available Performance OUTPUT POWER AT GENERATOR TERMINAL, MWe ae eo ~40 (-40) -20(4) 0 (32) 20 (68) INLET AIR TEMPERATURE, °C ("F) 40 (104) S130IPG-002M Aft End Right Side Forward End * Fuel Iniet + AC Power - Start Motor * Turbine Control Box * Turbine Cleaning + Generator Monitor Box * Fuel Filter, Combustor and Left Side Exhaust Collector Drains * Auxiliary Air (optional) for: — Liquid Fuel Atomizing —- Self-Cleaning Fitter + AC Power — Liquid Fuel Pump (optional) + Package Ground Lube Oil: Drain, Vent, Cooler Generator Control Box, Power Generator Drip Pan Drain AC Power — Lube Tank Heater — Pre/Post Lube Pump - Backup Lube Pump Length: Width: Height: Approx. Weight: CADETS OTS 1 RT EE ES BOT, Solar Turbines Incorporated P.O. Box 85376 San Diego, CA 92186-5376 U.S.A. Caterpillar is a trademark o pillar inc. Solar. Titan and SoLONO, a arks of Solar Turbines incorporated. Specifications subject to hout notice. Printed in U.S.A ©1999 Solar Turbines Incorporated. All rights reserved DS1301PG/699/2M FOR MORE INFORMATION Telephone: (+1) 619-544-5352 Telefax: (+1) 619-544-2633 Internet: www.solarturbines.com Package Dimensions 14 630 mm (48' 0") 3150 mm (10° 4") 4064 mm (13' 4”) 74 750 kg (165,000 Ib) ba BUDGETARY PROPOSAL CUSTOMER: Precision Energy Services PRODUCT: One Cyclone Generator Package ALSTOM REF #: HO1Nxxxx BJT Date: April 29, 2002 PROPOSAL INCLUDES: SCOPE OF SUPPLY PRICING AND DELIVERY TURBINE PERFORMANCE DIMENSIONAL DATA LAYOUT DRAWING ALSTOM Power Inc May 29, 2001 10730 Telge Rd. Houston Texas, 77095 Tel: (281) 856-4400 Pane anee 22 ALSTOM SCOPE OF SUPPLY 12.9 MW(e) Engine Core with Dry Low Emissions (DLE), axial exhaust, and instrumentation including temperature & vibration monitoring Fabricated baseplate with multi-point mounting to carry the gas turbine, gearbox, auxiliaries and generator with an integral lubricating oil tank On-skid lubricating oil system with duplex type 10 micron oil filter and air blast lube oil cooler suitable for ambient temperatures to 95°F (35°C) Turbine compressor cleaning system for hot and cold crank wash with mobile wash trolley with polypropylene tank AC electric motor driven hydrostatic starting system DLE Gas Fuel System with on-skid gas fuel piping in stainless steel, two rapid-acting gas shut-off valves with vent, Main & pilot fuel metering system with actuators, and pressure transmitters upstream and downstream of the fuel metering valves Air intake system including pulse type self cleaning combustion air intake and combustion air intake silencer, both constructed from painted carbon Exhaust system including secondary axial exhaust diffuser constructed from stainless steel! Acoustic enclosure fitted over the turbine, gearbox and generator, for average sound attenuation to 85cB(A) SPL at 3ft (1m) from the package and 5ft (1.5m) above including a ventilation system with filters, fans, dampers, silencers and vent hood with screens, and a fire and gas system including ultra-violet, heat and gas detectors, twin shot CQ: fire protection system with extinguishant release audible and visible alarms suitable for Class 1, Div.2, Group D areas Direct coupled epicyclic speed reducing gearbox with output speed of 1800 rom equipped with an accelerometer type vibration probe Dry diaphragm coupling with coupling guard constructed from aluminum An open ventilated 1800 rpm, 13.8 kV, 60 Hz, 0.8 power factor generator, nominally rated to match the turbine output at 59°F (15°C), Class 'F' insulation with class 'F' total temperatures Generator control panel, mounted on-skid, of steel construction containing an Page 1 of 5 ALSTOM automatic voltage regulator, automatic and manual synchronizing facility with check synchronizer, and generator metering equipment and electrical protection e On-skid two bay cabinet and PLC based control system e Package installation materials including hold down bolts, exhaust diffuser roll out gear, lube oil flushing kit, set of touch up paints e Turbine maintenance equipment including core engine roll-out stand, maintenance lifting frame and equipment, hand chain hoist, gearbox hand barring equipment and one set of tools for on-site maintenance e Standard set of certified information and approval drawings e Operator, Maintenance & Generator manuals e Standard brake test of turbine core engine e Standard frame and system test e Delivered Ex-works, Houston, TX e Packed for immediate site delivery NOTE ALSTOM Power does not accept any responsibility for Items that are outside Its scope of supply as described in section 1.1 of this document. Where items are not specifically described or addressed in section 1.1 of this budgetary offer, ALSTOM Power views these Items as excluded from the Scope of Supply. Page 2 of 5 ALSTOM PRICING AND DELIVERY Pricing One (1) Cyclone 12.9 MWe gas turbine generating package as described in the scope of supply Total Price (each): USS 4,500,000.00 (Four million five hundred thousand US dollars) Delivery At this time ALSTOM POWER estimates that the goods offered in this budgetary proposal will be ready for dispatch, ex-works, in 43 weeks, provided that full and final instructions to proceed were received at the time of order placement. The dispatch period would be confirmed at a later date. Defect Liability Period The contractor shall be liable for defects in the goods, in accordance with the contract conditions, for a period of twelve (12) months from first use or eighteen (18) months from readiness for delivery by ALSTOM POWER, whichever period shall expire first. ; Terms & Condition This offer is per ALSTOM Power, Inc. Standard Terms & Conditions of contract. Page 3 of 5 ALSTOM Turbine Performance - DLE Combustion System. Performance Cyclone Natural Gas Fuel (performance based on 100% load, Oft, 60% RH, 0/0” in H2O inlet/exhaust losses, 99% gearbox efficiency, 97 generator efficiency) Lambienttemo [erec) | ova | 1549) | soen | asi | secs | 75024 | 90,32 | sere a mene Output kJ/kW-hr 10146 10225 10350 10513 10686 10947 11214 i (a ae Se kg/s 45.7 447 43.1 37.6 P= TS STS SSS Cyclone Liquid Diesel Fuel (performance based on 100% load, Oft, 60% RH, 0"/0" in H2O inlet/exhaust losses, 99% gearbox efficiency, 97 generator efficiency) Lambienttemp | erecy | ova | 15¢9) | coun | asi | so | 75 (24 Fl ed bel Output kJ/kW-hr 10226 10379 10543 10744 10980 11308 92.2 Exhaust Flow 9643 8854 11037 11411 12039 70.8 Dimensional Data Cyclone Nominal 12.9 MW Package Page 4 of 5 § 405 eBpg 7 = TF Tae aaa ST rte : Fuwooio F, le eae PVs ie cout Soturmeg sore h bw. abe We oe Bie aihee dhe bean AS"OM Power MWCI0IO 1 NE Siow” seen RSI Tome Te awe we a ee) SS =T= iw an TSP PTO ss 1] GAS TOBIN PHRISL rere | —] 7 ae oe F088 ae 3 | Towatt ta we eS un [esas T_[Ture Ne VENT ATION AIR Im? T OT] ome Sante array a OUTED OF Le 5 ¢_[Cow.STicw ATR MLCT oucTING Z Fuh St STIRS i + | comest Tar omrat Oy Fe WC ACWTLAT OW AUR EATRICT Fak i | Bw. S1-SISTON SPURL § 1 Re ' [11 —T corenton venice ox remce i 2 [urtriarwisure Kt Mer ome fon wiss Garscre Te Jo, one J 3 [ws moat Z| [75 [oe vw car OT AT Ta 5 17 [Ra ORTATION OUTTA Te WaT Teves AT IMT ATTEN ia 70 a c ' 20, i \ \ Cc / [Sao tax Oo re = . tt son — I ae NZ son ! " a ii /! @ \ a ees iS | abe ie \ 4+ ede | Ue), cont 7 \- = $ mated py | é ‘ a = @ EL | i \ : xo ee ye | . ‘ i 7 aoe sez ‘4 ’ 2 <flagall= RS Q | : oaths ee } ql ah oes \ i | oO) my ’ i 1 ya WZ, 1 ’ “Ire Ht 4 oon in ~ ft 000639 | ' 1 sporoe, o {£3 y i sense 1 fa yt me Sd } 7 rl yt sere ~T ; WMS STANDARD CYC! ONE 1 AVOUT . \ / SNoutoaen Paceace Ny \ Ms om | 80 = ALPHA GENERATOR ‘\— hn 2 =e = ON SHO COUIHO.S COUPEN! j—2700 @ we el 700. #300 es ASAT in e509 = rE, STE een Te MWOI010 | roms: weMOVER Fan: - A “ 15- 3/68 FPPRRRB Peete =x r r es — ————- ———r rey ye UIMDIg JNOAD WOLSTV Precision Energy Services (PES) GT Pro Graphics GT PRO 10.3.2 Alstom User Net Power 10856 kW LHV Heat Rate 8813 BTUKWh 147 a — 245.4 a iz . 1X User Def GT Tho wae 14.99p 44.32 %02 2408m ] 979T 4.107 %CO2+S02 Onelev 245.4M 4.477 %H20 1455p 35T a 240.6 m Distillate O11 4.858 m = LHV 88376 KBTUh 154T 39.07M 50,04 p 304T 20M ee be TO 322T 245.8M 245.4M <~——~ 17.19p 6524p 427p 6427p B21p —_—— 200T 3s7T 484T 404T 754T 39.07M 39.59M 30.59M 392M 342M 352 4a 530 977 1080 0.4007 M 1-04-2002 09:36:20 file=S:\Applications...nd Run GT Pro Data 4.4.02.gtp Created By: Jeremy Wilkerson Date: April 5, 2002 @ GE Aero Energy Products A GE Power Systems Business GE10-60 Hz GAS TURBINE GENERATOR PACKAGE BUDGETARY PROPOSAL CUSTOMER: Precision Energy Services Inc. LOCATION-Alaska Mining Project CMS PROJECT NO. 400571 PREPARED BY: Bill Weaver Date : May 3, 2002 REVIEWED BY: Ken Stevens Date : May 3, 2002 GE Aero Energy Products PO BOX 4414 Houston, TX 77210-4414 Tel: (713) 803-0900 Fax: (713) 803-0390 GE PROPRIETARY INFORMATION The information contained in this document is GE proprietary information and is disclosed in confidence. It is the property of GE and shall not be used, disclosed to others or reproduced without express written consent of GE. If consent is given for reproduction in whole or part, this notice and the notice on each page of this document shall appear in any such reproduction in whole or part. A Subsidiary of General Electric Company TABLE OF CONTENTS 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 PROPOSAL SUMMARY BASIS OF PRICING BASIC SCOPE OF SUPPLY OPTIONAL EQUIPMENT AND SERVICES DESCRIPTION EXCLUSIONS TYPICAL PERFORMANCE DRAWINGS SPECIFICATIONS GENERAL TERMS AND CONDITIONS GE PROPRIETARY INFORMATION Subject to restriction on cover of first page. A Subsidiary of General Electric Company 2 1.0 PROPOSAL SUMMARY 1 Ea. GE10 Dual Fuel DLN Gas Turbine Generator Package GE PROPRIETARY INFORMATION Subject to restriction on cover of first page. A Subsidiary of General Electric Company 2 2 2.0 BASIS OF PRICING A. Validity: This proposal is budgetary and is valid for sixty days from issue date, subject to prior sale. B. Taxes: Sales taxes, tariffs, import duties applicable outside country of package production are not included in this proposal. 24 PRICES A. Base Offer One (1) GE10 DLN Dual Fuel Gas Turbine Generator Set and auxiliaries as described in the basic scope of supply. Base Price US $3,980,000.00 B. Optional Equipment 1. Winterization of the GE10 gas turbine package US $235,000.00 2. Commissioning tools and parts US$ 12,270.00 3. Startup & field testing (labor) US $ See attached Field service rates 4. Power Management Options (list) US $ Responded to under separate cover 5. Switchgear US $ 43,750.00 6. MCC US $ 32,620.00 7. Cold climate protection heating US $235,000.00 8. Program Management and Engineering US $ See attached Field service rates 9. Diverter, by-pass stack & structure. US $370,000.00 10. Exhaust Silencer (included with option 9) US $ included in above 11. Shipping: FOB, Houston TX. US $125,000.00 Other Items Steam Turbines, HRSG. US $ Responded to Under separate cover 2.2 PAYMENT SCHEDULE This proposal is based upon receipt of the following progress payments. EVENT % OF CONTRACT Down payment : 20% Monthly Installments 70% Ready for Shipment Ex-Factory 10% GE PROPRIETARY INFORMATION Subject to restriction on cover of first page. A Subsidiary of General Electric Company 4 2.3 2.4 2.5 SCHEDULE AND SHIPMENT Based upon present manufacturing commitments, the shipment date offered is eight (8) months from receipt of order, Ex-works Houston, TX, subject to prior sale. TERMS AND CONDITIONS OF SALE This offering is made subject to the General Terms and Conditions for sale of equipment and services included in this proposal. DRAWINGS AND DATA SUBMITTAL GE Aero Energy Products will provide drawings and data to Buyer (or EPC Contractor as designated by Buyer) in accordance with the GE Aero Energy Products standard drawing schedule (available upon request). GE PROPRIETARY INFORMATION Subject to restriction on cover of first page. A Subsidiary of General Electric Company 5 af GT MASTER 10.2.1 Larry Salguero GE Aero Energy Products - PES Alaska Project Net Power 14513 kW 1x GE10 DLE: 100% GT Capacity LHV Heat Rate 8483 BTU/kWh 14:67 pe rn LSS SS = SS ae =] 45T —>' 1X User Def GT 77.13 %N2+Ar | 60 %RH 14.96 p 15.03 %02 { 379.2m 903 T 3.639 %CO2+S02 | 40 ft elev 385.9 M 4.202 %H20 14.49 p 457 379.2m Distillate Oil 6.764 m LHV 123113 kBTU/h 615.3p 750 T 0.7401 M 42.61M LOA 150 p 358 T 10M a Wilt 10°06 = | 1 | | | 2 1 ! ge © a4 | S| ! i | 13 { I | |4 1 | ro | | I | | 1 | Li» = ie Belt Ld =o oe oe ees eee aod 1 | | Sy | | I ft Pe2 | {HPBT] \ PSS ‘@ ir ae 899 T 385.9M 103p 103p 99.07 p 659.1 p 659.1 p 6369p 9 7777 324:F 330 T. 350T 487T 496 T 756 T 52.62 M 9.27M 8.259 M47 Fe! 42.56M 42.56M 289 345 432 435 512 824 899 plpsia], TIF], Mikpphi, S »perties: Thermotiow - STQUIK 232 04-02-2002 e=c:\Tflow6\MYFiLES\CTMAS GTM ~~ ® ep) po ie) area © ca ® = ® © ® = 2 — a eo ” Ly) © ] 1 es aE © Product Overview GE Mark VI Controls *High Efficieney Design by Aircraft Engines and Power Systems *Extensively Tested for Performance and Mechanical Integrity GE Frame 1&3 Architecture ee Demonstrated Frame Design Minimizes C New DLE CGT PRES tls erin 25 ppm Nox 20 ppm CO *Proven PG TLIOA MT em rome ccd riay| +> 1.9 Million operating hours Ultra - Low NOX Combustion System Main Fuel XONON mine Lig Unit Preburner miels) Fs 2300 °F 660. °F ANE ae fer es eee - ~=J NOx <3 rane See ppm Compressor Drive s Turbine mp anrsleictt DATE: July 29, 2002 DIVISION OF ENERGY PROJECT NAME: Calista Feasibility Study FUNDING SOURCE(S): RTA/OTE FY93 BUDGET CODE: 83602 PROJECT MANAGER: ete an SENATE/HOUSE DISTRICTS: Lower Kuskokwim Region PROJECT DESCRIPTION: The intent of the Feasibility Study is to identify the potential for Calista's organizing a consolidated utility or managing utility services in the Lower Kuskokwim area. Research, planning, conditions of operations, and a report will be produced as a result of this feasibility study. The study will address the aspects of a consolidated/regional utility and the communities it plans to service. SCOPE OF WORK: The following tasks will be performed: a) Research of utility information of the area, but not necessarily duplicating any work or studies that have been completed previously; b) Identify the organizational structure of a proposed study; c) Prepare a 20-yr. load forecast; d) Complete a cost- of-service analysis; e) Develop a financial plan forecast; f) Prepare and publish a fact-finding report. PROJECT MANAGEMENT PLAN/LOCAL CONTRIBUTION: AEA will oversee a $30,000 grant given to the Calista Corporation for the purpose of a "Regional Utility Feasibility Study." Bettine & Associates contracted to do the work. Calista will provide some of their staff, facilities, and resources to compliment the logistics of the study, where needed. PROJECT STATUS: Calista will use its contractor, Bettine & Associates, to manage the study. Scope of work completed and final report submitted. PROJECT SCHEDULE/MILESTONES: Start Date: 3/93 End Date: 6/93 Calista Feasibility Study completed. 8/93 Grant closed-out. PROJECT CLOSEOUT: 8/93 Fn:H:\RP\STATUS\BTIEDEMAN\CALF3602.DOC Provides “flameless” reaction pathway with lower.activation energy Avoids temperatures where NOx is formed. Generates hot gases for turbine without producing NOx Expected Performance Full Load Od <3 ppm co 1.7 ppm ca [es O ppm 75% Load NOx, CO, UHC <10 ppm B.3. Bethel Utilities, Inc. — Selected Tariff Documents APUC No. 43 42" Revised Sheet No. 30.5 Canceling 41* Revised Sheet No. 30.5 BETHEL UTILITIES CORPORATION D. DETERMINATION OF COST OF POWER AJDUSTMENT 1. Estimated costs for three months beginning April 1, 2002 Estimated Estimated Source Quantity Unit Cost Total Diesel Fuel 703,900 gal. $1.9142 $1,347,405 Purchased Power 0 KWH 0.0000 0 Total $1,347,405 Balance in COPA balancing account as of April 1, 2002 $ <48,843> Total of (1) and (2) $1,298,562 Estimated KWH’s for the period 9,124,379 Projected cost of power (3) / (4) $0.1423/K WH Base cost of power $0. 0968/KWH Cost of power adjustment (5) less (6) $0.0455 E. REVISION OF FUEL COST RATE ADJUSTMENT 1. Every three months, the Company will submit a filing to the Alaska Public Utilities Commission and present the revised COPA. 2. The information to be contained in a filing to revise the COPA will include the following: a. A tariff advice letter. b. All necessary tariff sheets. . c. A schedule showing the number of gallons and amount spent for fuel in the past 12 months. Note: Previous surcharge calculation is shown on 65" Revised Sheet No. 30.1 Issued By Bethel Utilities Corporatio Sfoz a oO By: TS Last { Thomas S. Sterrett, Jr. Title: Controller 12 MONTH PERIOD PRECEDING COST OF POWER ADJUSTMENT Utility Name: TA Number: Month/Year April - 01 May -01 June -01 July - 01 August — 01 September — 01 October — 01 November — 01 December — 01 January — 02 February — 02 March — 02 153-43 Bethel Utilities Corporation FUEL PURCHASES Gallons Dollars 246,000 $495,419 242,200 $487,767 215,700 $419,100 231,600 $439,002 252,000 $457,229 227,200 $421,287 268,800 $512,466 268,800 $514,523 312,800 $602,712 288,400 $552,041 257,600 $493,085 256,800 $491,554 3,067,900 $5,886,185 KWH Sold 3,243,203 3,112,188 2,768,988 2,906,605 3,150,090 2,852,652 3,351,171 3,467,421 3,691,039 3,987,349 3,425,927 3,382,103 39,338,736 APUC No. 43 64" Revised Sheet No. 30.3 Canceling 63 Revised Sheet No. 30.3 BETHEL UTILITIES CORPORATION RATE FOR PURCHASE OF NON-FIRM POWER FROM QUALIFYING FACILITIES With variable operating and maintenance expenses set to zero, the rate at which non-firm power will be purchased from qualifying facilities will include only the avoided fuel cost of power which is calculated on Sheet No. 30.5 (D) (5). Avoided fuel cost of power $ 0.1423/KWH This filing pursuant to order No. 5 of Docket U-81-35. Tariff Advice No. 153-43 Effective: 0501702 Issued by: Bethel Utilities —t 1 By: “JSS Z - Title: Controller Thomas S. Sterrett, Jr. APUC No. 43 95" Revised Sheet No. 30.2 Canceling 94" Revised Sheet No. _30.2 BETHEL UTILITIES CORPORATION POWER COST EQUALIZATION The following conditions apply to Power Cost Equalization (PCE) eligibility. 1. Except for public schools, customers that are classified as state or federal offices or state or federal facilities are not eligible for PCE. . Customers that are classified as local community facilities are eligible for PCE, calculated in the aggregate for each community served by Bethel Utilities Corporation, Inc. for actual consumption of not more than 70 kilowatt-hours per month for each resident of the community. The number of community residents shall be determined under AS 29.60.020. . Customers not listed above are eligible for PCE for actual consumption of not more than 500 kilowatt-hours per month. If.appropriations are sufficient for payment in full, the amount of Power Cost Equalization to be credited to the bills of all eligible customers rendered on or after the effective date set forth below, is as follows: Single Phase $0.1124/KWH Three Phase $0.03 13/KWH As 42.05.110(1) provides that when appropriations are insufficient for payment in full, the amount paid to each utility is reduced on a pro rata basis. The Division of Energy, Department of Community and Economic Development has notified the Commission that funding is not sufficient to cover the fiscal year 2002 (FY02) PCE Program requirements and that the shortfall will require a 20% reduction in the PCE levels effective with the fseeFY02 billing period. Beginning with that billing period, the amount of PCE to be credit¢d to the bills of all eligible customers is as shown below: Ze is de fh Single Phase $0.0899/K WH R Three Phase $0.0250/KWH R The Equalization will be discussed separately on each customer billing with the following notice: ALASKA POWER COST EQUALIZATION CREDIT X.XX Tariff Advice No. 153-43 Effective: 05/016 Title: Controller Thomas S. Sterrett, Jr. Original sheet No 2274 RECEIVED SEP 17 1991 _ State of Alaska Public Utilities Commission APUC No. __43 Cancelling Sheet No. BETHEL UTILITIES CORPORATION FUEL COST RATE ADJUSTMENT A. APPLICABILITY - N All tariff rate schedules shall be subject to the applicable fuel cost rate adjustment (FCRA) as set forth in (D) below. B. COST OF POWER ADJUSTMENT The base cost of fuel is $ 0.0968/kilowatt hour. Billings to customers will be increased or decreased to reflect the COPA surcharge calculated to reconcile the Company’s allowable fuel and purchased power expenses with revenues designed to cover those expenses. C. BALANCING ACCOUNT The Company will maintain a balancing account beginning September 1, 1991, with balances thereafter reflecting the sum of monthly debit and credit entries described as follows: 1. A debit entry for the amount spent for fuel. 2. A debit entry for the amount spent to purchase power. 3. A credit entry for the amount of kilowatt hours sold times the base fuel cost of power. 4. A credit entry for the amount of kilowatt hours sold times the COPA actually assessed. S. Other entries as directed by the Alaska Public Utilities Commission. N Pursuant to Order No. 2 in Docket U-91-10 10/1/91 Tariff Advice No. 22 Effective: isa BETHEL UJILITIES CORPORATION By: 7 = lua ‘A Title: CONTROLLER THOMAS S. STERRETT,, APUC No. __43 10th Revised Sheet No. 31 RECEIVED f Cancelling JAN 06 1992 9th Revised Sr Sheet No _ State of Alaska - Public Utilities Commission BETHEL UTILITIES CORPORATION SCHEDULE OF RATES FOR POWER SINGLE PHASE APPLICABLE TO: Any customer service receiving single phase power. CHARACTER OF SERVICE: Continuous alternating current at 60 cycles 208/120 or 240/120 volts single phase. Specific characteristics depend upon customer needs, available circuits and/or special agreements. RATES PER MONTH: » Customer Charge: A $6.65 customer charge will be applied to each customer account for each billing statement rendered, whether for a full month of service or any fraction thereof. Energy Charge: All kilowatt hours shall be billed at $0.2158 per kilowatt hour. I POWER COST EQUALIZATION: These rates are eligible for power cost equalization in an amount per KWH defined on Sheet No. 30.2. COST OF POWER ADJUSTMENTS: A surcharge or credit may be applied to each billing rendered under this schedule to reflect increases or decreases in the cost of power compared to a cost of $0.0968 and shall be calculated as shown on Sheet No. 30.5). ooo a — — — — — ——— Pursuant to Order No. 2 in Docket U-91-58 Tariff Advice No. Ettective:2/20/91 BETHEL UTHITIES CORPORATION Issued by: By: L S$ THOMAS S. STERRETTAR. Title: CONTROLLER APUC No. __43 9th Revised Sheet No22 RECEIVED f Cancelling JAN 0 8th Revised 33 6 1992 State of Alaska Public Utilities Commission BETHEL UTILITIES CORPORATION SCHEDULE OF RATES FOR POWER THREE PHASE APPLICABLE TO: Any customer service receiving three phase power. To receive three phase service the customer must be a commercial or governmental entity and have installed equipment requiring three phase power. CHARACTER OF SERVICE: Continuous alternating current at 60 cycles 7,200, 2,400, 480, 240/120 or 208/120 volts three phase. Specific characteristics depend upon customer needs, available circuits and/or special agreements. RATES PER MONTH: Customer Charge: A $20.00 customer charge will be applied to each customer account for each billing statement rendered, whether for a full month of service or any fraction thereof. Demand Charge: All kilowatts of demand shall be billed at $22.21 per kilowatt. The minimum I billable demand shall be 8 kilowatts or 80% of the maximum recorded demand during the preceding 12 month period, whichever is greater. Energy Charge: All kilowatt hours shall be billed at $0.1054 per kilowatt hour. qh POWER COST EQUALIZATION: These rates are eligible for power cost equalization in an amount per KWH defined on Sheet No. 30.2. ,10s4 rose, Tea ve Pursuant to Order No. 2 in Docket U-91-58 Tariff Advice No. Effective 2/29/92 Issued by: BETHEL UTLITIES CORPORATION “ZSS THOMAS S. STERR Title: CONTROLLER h APUC No. __43 5th Revised 34 RECEIVED Sheet No. es Cancelling SEP 1 7 1991 4 Revised 34 State of Alaska , i Public Utilities Commission SCHEDULE OF RATES FOR POWER THREE PHASE (Continued) - COST OF POWER ADJUSTMENTS: A surcharge or credit may be applied to each billing rendered under this schedule to reflect increases or decreases in the cost of powercompared to a cost of $0.0968/KWH Cc and shall be calculated as shown on Sheet No. 30.5. c Tariff Advice No. __93 Effective: 10/01/91 BETHEL UTILITIES CORPORATION ICE-PRESIDENT C.1. Spread Sheet Data 10 Donlin Creek Mine Alternatives Fuel Inflation Factor = 4.00% Turbine Heal Rate in BTU/KWh: General inflation Factor == 3.00% ‘Tank Farm Cost per Gallon Discount Rate = 3.50% Fuel cost $/Gal 30 MW Combustion Turbine Plant at Mine Site for 25 MW Mine Load Year 2006 2007 2008 2009 Power Requirements KWs Doniin Gold Mine 25,000 25,000 25,000 25,000 Total KW 25,000 25,000 25,000 25,000 KWHs Donlin Gold Mine 208,050,000 208,050,000 208,050,000 208,050,000 T-Line losses 0 0 0 ° Total 208,050,000 208,050,000 208,050,000 208,050,000 Installed Capacity Combustion Turbine 30,000 30,000 30,000 30,000 Battery Storage System 1,000 1,000 1,000 1,000 Total Capacity in KWs 31,000 31,000 31,000 31,000 Generation KWHs Combustion Turbine Mine 208,050,000 208,050,000 208,050,000 208,050,000 Plant CosuKW Combustion Turbine $890 $800 $890 $890 Battery Storage System $1,000 $1,000 $1,000 $1,000 T-Line per Mile 0 » 0 0 Capital Cost ($1000) Generation ‘Combustion Turbine $26,700,000 $26,700,000 $28,700,000 $26,700,000 Battery Storage System $1,000,000 $1,000,000 $1,000,000 _ $1,000,000 Total $26,700,000 $26,700,000 $28,700,000 $26,700,000 Transmission Line Length in Miles 0 ° ° 0 T-Line Cost $0 0 30 $0 Substations $1,000,000 $1,000,000 $1,000,000 $1,000,000 Total $1,000,000 $1,000,000 ‘$1,000,000 $1,000,000 Year 2008 2007 2008 2008 Fuel Storage Gallons Mine 8,503,370 «8,503,370 8,893,370 8,503,370 Fuel Storage Costs $/Gallon Mine $1.40 $1.40 $140 $1.40 Fuel Storage Costs Mine — $12,030,717 $12,030,717 $12,030,717 $12,030,717 Total Fuel Oll Storage $12,030,717 $12,030,717 $12,030,717 $12,030,717 Total Capital Costs $39,730,717 $30,730,717 $39,730,717 $39,730,717 Operating Reserves, Spare $3,973,072 $3,073,072 $3,973,072 $3,973,072 Parts and Contingency at 10% Total Costs $43,703,789 $43,703,780 $43,703,789 $43,703,780 Operating Costs Annual Fuel Requirements #2 Fuel OllGalions 11,457,826 11,457,828 11,457,828 11,457,826 #2 Fuel Oli $/Gallions $1.55 $1.61 $1.68 $1.74 ‘Annual Fuel Costs $17,759,830 $18,470,016 $19,208,818 $10,077,169 osm ‘Combustion Turbine $/KWh 0.0050 0.0052 0.0053 0.0055 Annual O&M Turbine —-—«$1,040,250 $1,071,458 $1,103,601 $1,136,709 T-Line @ $1000/mi $0 30 $0 90 Annual T-line Cost $0 $0 $0 $0 Total $1,040,250 $1,071,458 $1,103,601 $1,136,709 Mine site analysisSheet5 $1.40 $1.55 2010 25,000 25,000 208,050,000 208,050,000 30,000 1,000 31,000 208,050,000 $28,700,000 $1,000,000 ‘$28,700,000 1,000,000 $1,000,000 2010 8,593,370 $1.40 $12,030,717 $12,030,717 $39,730,717 $3,073,072 ‘$43,703,789 11,457,826 $1.81 $20,776,256 0.0056 $1,170,811 $0 $0 $1,170,811 40 MW Combustion Turbine Plant at Mine Site for 35 MW Mine Load Year 2008 2007 2008 2009 2010 Power Requirements KWs Donlin Gold Mine 35,000 35,000 35,000 35,000 35,000 Total KW 35,000 35,000 38,000 35,000 35,000 KWHs Donlin Gold Mine 201,270,000 281,270,000 291,270,000 291,270,000 201,270,000 T-Line losses: ° 0 0 0 o Total 281,270,000 291,270,000 291,270,000 201,270,000 291,270,000 Installed Capacity Combustion Turbine 40,000 40,000 40,000 40,000 140,000 Battery Storage System 1,000 1,000 1,000 1,000 1,000 ‘Total Capacity in KWs 41,000 41,000 41,000 41,000 41,000 Generation KWHs ‘Combustion Turbine Mine 291,270,000 291,270,000 291,270,000 291,270,000 291,270,000 Plant CosuKW Combustion Turbine $890 $890 $890 $290 $890 Battery Storage System $1,000 $1,000 $1,000 $1,000 $1,000 T-Line per Mile 0 Po 2 $0 $0 Capital Cost ($1000) Generation Combustion Turbine $35,600,000 $35,600,000 $35,600,000 $35,600,000 $35,600,000 Battery Storage System —_ $1,000,000 $1,000,000 $1,000,000 $1,000,000 $1,000,000 Total $35,600,000 $35,600,000 $35,600,000 $35,600,000 $35,600,000 ‘Transmission Line Length In Miles 0 0 0 o 0 T-Line Cost J 0 0 %0 $0 Substations $1,000,000 $1,000,000 $1,000,000 $1,000,000 $1,000,000 Total $1,000,000 $1,000,000 $1,000,000 $1,000,000 $1,000,000 Year 2008 2007 2008 2008 2010 Fuel Storage Gations Mine 12,030,717 12,030,717 12,030,717 12,030,717 12,030,717 Fuel Storage Costs $/Gallon Mine 31.40 $1.40 $1.40 $1.40 $1.40 Fuel Storage Costs Mine $16,643,004 $16,843,004 $16,843,004 $16,643,004 ‘Total Fuel Oli Storage $16,843,004 $16,843,004 $16,843,004 $16,843,004 Total Capttal Costs $53,443,004 $53,443,004 $53,443,004 $53,443,004 Operating Reserves, Spare $5,344,300 $5,344,300 $5,344,300 $5,344,300 $5,344,300 Parts and Contingency at 10% Total Costs $58,767,908 $58,787,305 $58,787,305 $58,787,305 $58,787,305 ‘Operating Costs Annual Fuel Requirements #2 Fuel Oil Gallons 16,040,957 16,040,957 16,040,957 ‘#2 Fuel Oll $/Gallons $1.55 $1.61 $1.8 Annual Fuel Costs $24,883,483 $25,858,022 $20,086,758 O&M ‘Combustion Turbine $/kWh 0.0050 0.0052 0.0053 0.0055 0.0056 Annual O&M Turbine $1,458,350 $1,500,041 $1,545,042 $1,501,303 $1,630,135 T-Line @ $1000/mi ro cl 0 0 Sd Annual T-fine Cost $0 $0 $0 $0 $0 Total $1,456,350 $1,500,041 $1,545,042 $1,501,303 $1,630,135 Year Total O&M Interest During Constuction 0% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 15 Year Financing 0% 5% 8% Capital Cost #kWh 0% 5% 8% O&M $kWh Total Cost $/kWh 0% 5% 8% 20 Year Financing 0% 5% 8% Capital Cost Wh O% 5% 8% 8M SkWh Total Cost $/kWh 0% 5% 8% 30 Year Financing 0% % 8% Capttal Cost SWh 0% 5% 8% O&M SKWh Total Cost SkWh 0% 5% 8% Grant Funding Capital Cost O&M S/KWh_ Total Cost $/kWh Mine site analysisSheet5 2006 $18,799,880 $0 $2,185,189 $3,496,303 $43,703,789 $45,888,979 $47,200,002 2006 $2,913,586 $4,421,049 $5,514,365 $0.014 $0.021 $0.027 ‘$0.090 $0.104 $0.112 $0.117 $2,185,189 $3,682,250 $4,807,434 $0.011 $0.018 0.023 $0.101 $0.108 90.113 $1,456,793 $2,085,144 $4,192,663 $0.007 $0.014 90.020 90.090 $0.097 $0.105 90.111 $0.090 $0.000 2007 $19,541,473 $0 $2,185,189 $3,496,303 $43,703,789 $45,888,979 $47,200,002 2007 $2,913,586 $4,421,049 $5,514,365 $0.014 $0.021 $0.027 $0,094 $0.108 $0.115 $0.120 $2,185,189 $3,682,250 $4,007,434 30.011 30.018 $0.023 $0.104 90.112 80.117 $1,456,703 $2,005,144 $4,192,663 $0.007 $0.014 $0.020 90.094 $0.101 90.108 90.114 g £2, 2008 $20,312,418 so $2,185,189 $3,496,303 $43,703,789 $45,888,970 $47,200,092 2008 $2,913,586 $4,421,049 $5,514,365 $0.014 $0.021 $0.027 $0.112 $0.119 $0.124 $2,185,189 $3,682,250 $4,807,434 $0.011 $0.018 $0.023 0.108 $0.115 $0.121 $1,456,793 $2,985,144 $4,192,063 $0.007 $0.014 $0.020 $0008 90.105 $0.112 90.118 30.098 $0.098 2009 $21,113,878 $0 $2,185,189 $3,496,303 $43,703,789 $45,888,979 $47,200,002 2009 $2,013,586 $4,421,049 $5,514,365 $0.014 $0021 $0.027 $0.101 90.115 $0,123 $0.128 $2,185,189 $3,682,250 $4,007,434 $0.011 $0.018 $0.023 $0.101 90.112 90.119 90.125 $1,456,793 $2,085,144 $4,192,063 90.007 90.014 $0.020 $0.101 $0.108 90.118 90.122 $0.101 $0.101 2010 ‘$21,947,008 0 $2,185,189 $3,496,303 $43,703,789 $45,888,979 ‘$47,200,002 2010 $2,913,566 $4,421,040 $5,514,305 $0.014 $0,021 $0,027 $0.105 $0.119 $0.127 $0.132 $2,185,189 $3,682,250 $4,807,434 $0.011 90.018 90.023 $0.105 90.116 $0.123 90.129 $1,456,703 $2,085,144 $4,192,663 $0.007 90.014 $0.020 $0,105 90.112 $0.120 90.128 $0.1 $0.1 RRo Year Total O&M Interest During Constuction 0% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 15 Year Financing 0% 5% 8% Capital Cost $Wh 0% 5% 8% O&M $kWh Total Cost $/kWh 0% 5% 8% 20 Year Financing 0% 5% 8% Capital Cost kWh 0% 5% om 8M SkWh Total Cost /KWh Oo 5% 8% 30 Year Financing 0% 5% 8% Capital Cost $kwn O% 5% a% 08M SkWh Total Cost $k Wh 0% 5% 8% Grant Funding Capital Cost O&M $/kWh Total Cost $/kWh 2006 $26,319,633 $0 $2,930,365 $4,702,084 $58,787,305 $61,726,670 $63,490,289 2006 $3,919,154 $5,046,889 $7,417,542 $0.013 $0.020 $0.025 90.104 90.111 90.116 $2,939,365 $4,953,108 $8,466,626 $0.010 90.017 $0.022 90.100 90.107 $0.113 $1,059,877 $4,015,408 $5,639,670 $0.007 $0.014 30.019 $0.000 $0.007 90.104 $0.110 2007 $27,358,062 0 $2,939,365 $4,702,984 ‘$58,787,305 961,726,670 $63,490,289 2007 $3,010,154 $5,046,889 $7,417,542 $0.013 $0.020 90.025 $0.094 $0.107 90.114 90.119 $2,930,305 $4,953,108 $8,486,626 90.010 90.017 $0.022 30.094 $0.104 90.111 90.116 $1,950,577 $4,015,408 $5,639,679 90.007 $0.014 90.019 90.094 $0.101 90.108 90.113 0 $0.004 $0.094 2008 $28,437,385 #0 $2,930,365 $4,702,984 $58,787,305 $61,726,670 $63,490,280 2008 $3,010,154 $5,046,689 $7,417,542 $0.013 $0.020 $0.025 90.111 $0.118 90.123 $2,939,365 $4,953,108 96,486,628 $0.010 $0.017 $0.022 $0.108 $0.15 $0.120 $1,959,577 $4,015,408 $5,639,670 $0.007 90.014 90.019 90.098 90.104 90.111 90.117 2009 $20,550,420 $2,039,365 $4,702,084 $58,767,305 $0.115 90.122 90.127 $2,039,365 $4,953,108 $8,486,628 $0.010 $0.017 90.022 $0.101 $0.112 $0.118 $0.124 $1,059,577 $4,015,408 $5,639,679 $0.007 90.014 90.019 $0.101 $0.108 90.115 $0.121 90.101 $0.101 2010 $30,725,603 90 $2,039,365 $4,702,084 $58,787,305 $61,726,670 $63,490,289 2010 $3,019,154 $5,046,889 $7,417,542 $0.013 0.020 90.025 $0.105 $0.119 90.128 90.131 $2,930,365 $4,953,108 $6,406,626 $0.010 $0.017 $0.022 $0.105 90.116 90.122 90.128 $1,950,577 $4,015,408 $5,630,670 $0.007 90.014 $0.019 90.105 $0.112 90.119 $0.125 $0.105 0.105 Dontin Creek Mine Alternatives Fuel Inflation Factor = 4.00% Turbine Heat Rate in BTU/KWh: General inflation Factor = 3.00% ‘Tank Farm Cost per Galion Discount Rate . 3.50% Fuel cost $/Gal 30 MW Combustion Turbine Plant at Crooked Creek for 25 MW Mine Load Year 2006 2007 2008 2009 Power Requirements KWs. Dontin Gold Mine 25,000 25,000 25,000 25,000 Total KW 25,000 25,000 25,000 25,000 KWHs T-Line losses oO 0 0 0 Total 208,050,000 208,050,000 208,050,000 208,050,000 Installed Capacity Combustion Turbine 30,000 30,000 30,000 30,000 Battery Storage System 1,000 1,000 1,000 1,000 Total Capacity in KWs 31,000 31,000 31,000 31,000 Generation KWH Combustion Turbine Mine 208,050,000 208,050,000 208,050,000 208,050,000 Plant CosukW Combustion Turbine $850 $850 $850 $850 Battery Storage System $1,000 $1,000 $1,000 $1,000 T-Line per Mile $525,000 $525,000 $525,000 $525,000 ‘Capital Cost ($1000) Generation Combustion Turbine $25,500,000 $25,500,000 $25,500,000 $25,500,000 Battery Storage System $1,000,000 ‘$1,000,000 $1,000,000 $1,000,000 Total $25,500,000 $25,500,000 $25,500,000 $25,500,000 ‘Transmission Line Length in Miles 15 15 15 18 T-Line Cost $7,875,000 $7,878,000 _—$7,875,000 ‘Substations: ‘$4,000,000 ‘$4,000,000 ‘$4,000,000 Total $11,875,000 $11,875,000 $11,875,000 Fuel Storage Gallons Cooked Creek 8,593,370 8,593,370 8,503,370 8,593,370 Fuel Storage Costs $/Gallon Crooked Creek $1.25 $1.25 $1.25 $1.25 Fuel Storage Costs Crooked Creek = $10,741,712 $10,741,712 $10,741,712 $10; Total Fuel Oli Storage $10,741,712 $10,741,712 $10,741,712 $10,741,712 Total Capital Costs $48,116,712 $48,116,712 $48,116,712 $48,116,712 Operating Reserves, Spare $4,811,671 $4,811,671 $4,811,671 $4,811,671 Parts and Contingency at 10% Total Costs $52,928,383 $52,928,383 $52,928,383 $52,928,383 Operating Costs Annual Fuel Requirements #2 Fuel Oll Gallons 11,457,826 11,457,626 = 11,457,826 11,457,826 #2 Fuel Oil $/Gallons $1.53 $1.59 $1.65 $1.72 Annual Fuel Costs $17,530,474 $18,231,693 $18,960,961 $19,719,300 8M ‘Combustion Turbine $/-kWh, 0.0050 0.0052 0.0053 0.0055 Annual O&M Turbine $1,040,250 $1,071,458 $1,103,601 $1,136,700 T-Line @ $1000/m! $15,000 $15,000 $15,000 $15,000 Total «$1,055,250 $1,086,458 $1,118,601 $1,151,709 $1.25 $1.53 2010 25,000 208,050,000 208,050,000 30,000 1,000 31,000 208,050,000 $1,000 $525,000 $25,500,000 $1,000,000 $25,500,000 15 $7,875,000 $4,000,000 $11,875,000 8,593,370 $128 $10,741,712 $10,741,712 $48,116,712 $4,811,671 $52,928,383 11,457,826 $1.70 $20,508,175 0.0056 $1,170,611 ‘$15,000 $1,185,611 Year kws Doniin Gold Mine Total KW KWHs. Donlin Gold Mine T-Line losses Total Installed Capacity Combustion Turbine Battery Storage System Total Capacity in KWs Generation KWHs Combustion Turbine Mine Plant CosKW Combustion Turbine Battery Storage System T-Line per Mile Capital Cost ($1000) Generation Combustion Turbine Battery Storage System Total Transmission Line Length in Miles T-Line Cost ‘Substations Total Fue! Storage Gallons ‘Cooked Creek Fuel Storage Costs $/Galion ‘Crooked Creek Fuel Storage Costs Crooked Creek Total Fuel Olt Storage Total Capital Costs Operating Reserves, Spare Parts and Contingency ‘at 10% Total Costs ‘Operating Costs Annual Fuel Requirements #2 Fuel Oil Gations #2 Fuel Oil $/Gallons Annual Fuel Costs 0am ‘Combustion Turbine $/kWh ‘Annual O8M Turbine ‘T-Line @ $1000/mi Total 40 MW Combustion Turbine Plant at Crooked Creek for 35 MW Mine Load 2006 2007 ‘35,000 35,000 35,000 35,000 291,270,000 291,270,000 o o 291,270,000 291,270,000 40,000 40,000 1,000 1,000 41,000 41,000 291,270,000 291,270,000 ‘$850 ‘$850 $1,000 ‘$1,000 $525,000 $525,000 $34,000,000 $34,000,000 $1,000,000 $1,000,000 $34,000,000 $34,000,000 15 15 $7,875,000 $7,875,000 ‘$5,000,000 ‘$5,000,000 $12,875,000 $12,875,000 12,090,717 12,030,717 $1.28 $1.25 $15,038,307 $15,038,397 $15,038,307 $15,038,307 961,013,307 $61,913,307 96,191,340 98,191,340 $88,104,736 $88,104,736 16,040,957 18,040,957 $1.53 $1.50 $24,542,663 $25,524,370 0.0080 0.0052 $1,456,350 $1,500,041 $15,000 $15,000 $1,471,350 $1,515,041 2008 35,000 35,000 291,270,000 291,270,000 40,000 1,000 41,000 291,270,000 $1,000 $525,000 ‘$34,000,000 $1,000,000 $34,000,000 18 $7,875,000 ‘$5,000,000 $12,875,000 12,030,717 $1.25 $15,038,307 $15,038,397 981,013,397 96,191,340 $88,104,796 16,040,057 $1.65 $26,545,345 0.0053 $1,545,042 $1,560,042 35,000 35,000 291,270,000 o 291,270,000 40,000 1,000 41,000 291,270,000 $1,000 $525,000 $34,000,000 $1,000,000 ‘$34,000,000 18 $7,875,000 $5,000,000 $12,875,000 12,030,717 $1.25 $15,038,397 $15,038,397 981,913,397 96,191,340 968,104,736 16,040,057 $1.72 $27,607,159 0.0055, $1,591,303 $15,000 $1,608,393 2010 35,000 35,000 291,270,000 291,270,000 40,000 41,000 (291,270,000 $1,000 $525,000 12,030,717 $1.25 $15,038,307 $15,038,307 16,040,057 $1.70 $28,711,445 0.0056 $1,630,135 $15,000 $1,654,135 Year Total O&M Interest During Constuction 0% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 15 Year Financing 0% 5% 8% Capital Cost $/kWh 0% 5% 8% 08M $kWh Total Cost $/kWh 0% 5% 8% 20 Year Financing 0% 5% e% Capital Cost kWh 0% 5% 8% O&M $kWh Total Cost $/kWh_ 0% 5% 8% 30 Year Financing 0% 5% ee Capital Cost $Wh 0% 5% 8% O&M $/kWh Total Cost kWh 0% 5% 8% Grant Funding Capital Cost O&M kWh Total Cost $/KWh 2006 $18,585,724 $0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 ‘$57,162,654 2006 $3,528,550 $5,354,204 $6,678,287 $0.017 90.028 $0.032 0.089 $0,106 90.115 $0.12 $2,648,419 $4,459,466 $5,822,143 $0.013 $0.021 0.028 $0.089 $0.102 90.119 $0.117 $1,764,279 $3,615,221 $5,077,612 $0.008 $0.017 $0.024 $0.089 $0.008 $0.107 0.114 2007 $19,318,150 $0 $2,646,419 4.234.271 2007 $3,528,550 $5,354,206 $6,678,287 $0.017 $0,026 $0.032 $0.093 $0.110 $0.119 $0.125 $2,646,410 $4,459,466 $5,622,143 $0.013 $0.021 $0.028 $0,093 $0.106 $0114 $0121 $1,764,279 $3,615,221 $5,077,612 90.008 90.017 $0,024 90.093 90.101 $0.110 $0.117 $0.093 ‘$0,093 2008 $20,079,562 $0 $2,646,419 $4,234,271 $52,028,383 $55,574,802 $57,162,654 2008 $3,528,559 $5,354,204 $8,678,287 $0.017 $0.026 $0.032 $0.097 90.113 90.122 $0.129 $2,646,419 $4,459,406 $5,822,143 90.013 90.021 30.028 $0.097 $0.108 90.118 90.124 $1,764,279 $3,615,221 $5,077,612 $0.008 $0.017 90.024 $0.097 $0.105 90.114 $0.121 $0.007 $0.097 2009 $20,871,108 $0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 $57,162,654 2009 $3,528,559 $5,354,204 $8,678,287 $0.017 $0.028 $0.032 $0.100 $0.117 90.126 $0.132 $2,646,419 $4,450,406 $5,822,143 $0.013 90.021 90.028 $0.100 90.113 $0.122 90.128 $1,764,279 $3,615,221 $5,077,612 $0,008 90.017 90.024 $0.100 $0.109 90.118 $0.125 $0.100 $0.100 2010 $21,693,986 so $2,046,419 $4,234,271 $52,928,383 $55,574,802 $57,162,654 2010 $3,528,559 $5,354,204 $6,676,287 $0.017 90.026 $0.032 $0.104 $0.121 $0.130 $0.136 $2,646,419 $4,450,468 $5,622,143 30.013 90.021 90.028 $0.104 $0.117 90.128 $0.132 $1,784,270 $3,615,221 $5,077,612 $0.008 90.017 90.024 $0.104 $0.113 90.122 $0.129 $0,104 $0.104 Year Total O&M Interest During Constuction O% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 15 Year Financing 0% s% 8% Capital Cost $kWh 0% 5% 8% 08M SkWh 2006 $26,014,013 $0 $3,405,237 $5,448,379 968,104,736 $4,540,316 96,680,434 $8,593,177 $0.016 30.024 $0,030 Capital Cost $/kWh 0% 5% 8% 8M $kWh Total Cost $/kWh O% 5% 8% 30 Year Financing 0% 5% % Capital Cost $KWh 0% 5% 8% 8M $kWh Total Cost $kWh 0% 5% 8% Grant Funding Capital Cost O&M SkWh Total Cost kWh $0.101 90.109 90.115 $2,270,158 $4,051,826 96,533,534 ‘$0.008 90.016 90.022 $0.089 $0.097 $0.105 90.112 0 90.089 $0.08 2007 $27,039,411 0 $3,405,237 $5,448,379 $88,104,736 $71,509,973 $73,553,115 2007 $4,540,316 $8,880,434 $8,503,177 $0.016 $0,024 $0.030 90.108 90.116 90.122 $3,405,237 $5,738,145 ‘$7,401,547 90.012 $0.020 90.026 $0.105 90.113 $0.119 $2,270,158 $4,051,826 $8,533,534 90.008 90.016 90.022 90.101 $0.109 90.115 2008 $28,105,387 so $3,405,237 $5,448,379 968,104,736 $71,509,073 $73,553,115 2008 $4,540,316 $6,880,434 $8,593,177 90.016 90.024 $0.030 $0,108 90.116 90.122 $2,270,158 $4,051,826 98,533,534 0.008 90.016 90.022 30.096 90.104 $0.112 90.119 2009 $29,213,552 $0 $3,405,237 $5,448,370 $88,104,736 $71,500,973 $73,553,115 2009 $4,540,316 $6,889,434 $8,593,177 90.016 90.024 $0.030 $0.100 90.116 90.124 90.130 $3,405,237 $5,738,145 $7,491,547 90.012 90.020 90.028 $0.100 90.112 90.120 $0.128 $2,270,158 $4,651,626 98,533,534 90.008 90.016 90.022 $0.100 90.108 $0.116 90.123 $0.100 $0.100 2010 $30,365,580 $0 $8,405,237 $5,448,370 $68,104,736 $71,509,973 $73,553,115 2010 $4,540,316 98,889,434 $8,593,177 $0.016 $0.024 $0.030 $0.104 90.120 $0.128 90.134 $3,405,237 $5,738,145 $7,491,547 $0.012 $0.020 $0.026 90.104 90.116 90.124 90.130 $2,270,158 $4,651,828 98,533,534 $0.008 30.016 $0.022 $0.104 90.112 90.120 90.127 0.104 90.104 08/10/2002 Donlin Creek Mine Altematives Fuel Inflation Factor = 4.00% Turbine Heat Rate in BTU/KWh General inflation Factor == 3.00% Tank Farm Cost per Gallon Discount Rate = 3.50% Fuel cost $/Gal 30 MW Combustion Turbine Plant at Crooked Creek for 25 MW Mine Load Year 2008 2007 2008 2009 Power Requirements KWs Donlin Gold Mine 25,000 25,000 25,000 25,000 Total KW 25,000 25,000 25,000 25,000 KWHs Donlin Gold Mine 208,050,000 208,050,000 208,050,000 208,050,000 T-Line losses 0 0 0 0 Total 208,050,000 208,050,000 208,050,000 208,050,000 Installed Capacity Combustion Turbine 30,000 30,000 30,000 30,000 Battery Storage System 1,000 1,000 1,000 1,000 Total Capacity in KWs 31,000 31,000 31,000 31,000 Generation KWHS ‘Combustion Turbine Mine 208,080,000 208,050,000 208,050,000 208,050,000 Plant CosuKW ‘Combustion Turbine $050 $850 $050 $850 Battery Storage System $1,000 $1,000 $1,000 $1,000 T-Line per Mile $525,000 $525,000 $525,000 $525,000 Capital Cost ($1000) Generation Combustion Turbine $25,500,000 $25,500,000 $25,500,000 $25,500,000 Battery Storage System $1,000,000 $1,000,000 Total $25,500,000 $25,500,000 Transmission Line Length in Miles 15 15 15 T-Line Cost $7,875,000 ‘Substations —_ $4,000,000 Total $11,875,000 $7,875,000 $7,875,000 ‘$4,000,000 $11,875,000 Fuel Storage Gallons Mine 8,593,370 8,593,370 8,503,370 8,593,370 Fuel Storage Costs $/Gallon Crooked Creek $1.25 $1.25 $1.25 $1.25 Fuel Storage Costs Crooked Creek $10,741,712 $10,741,712 $10,741,712 $10,741,712 Total Fuel Oil Storage $10,741,712 $10,741,712 $10,741,712 $10,741,712 Total Capital Costs $48,116,712 $48,116,712 $48,116,712 $48,116,712 Operating Reserves, Spare $4,811,871 $4,811,671 $4,811,671 $4,811,671 Parts and Contingency at 10% Total Costs $52,928,383 $52,928,383 $52,928,383 $52,026,383 ‘Operating Costs Annual Fue! Requirements. #2 Fuel Oil Gallons 10,312,043 10,312,043 10,312,043 10,312,043 #2 Fuel Oil $/Galions 31.53 $1.50 $1.85 $1.72 Annual Fuel Costs $15,777,427 $16,408,524 $17,084,885 $17,747,450 o8M ‘Combustion Turbine $/kWh_ 0.0050 0.0052 0.0053 0.0055, Annual O&M Turbine $1,040,250 $1,071,458 $1,103,601 $1,136,709 T-Line @ $1000/mi ‘$15,000 $15,000 $15,000 $15,000 Total «$1,055,250 $1,086,458 = $1,118,601 $1,151,709 Total O&M — $16,832,677 $17,404,081 $18,183,486 $18,899,168 Mine site anatysisSheet3 $1.25 $1.53 2010 25,000 25,000 208,050,000 208,050,000 30,000 1,000 31,000 208,050,000 $850 $1,000 $525,000 $25,500,000 $1,000,000 $25,500,000 15 $7,875,000 ‘$4,000,000 ‘$11,875,000 8,593,370 $1.25 $10,741,712 $10,741,712 $48,116,712 $4,811,671 $52,928,383 10,312,043 $1.79 $18,457,357 0.0056 $1,170,811 $15,000 $1,185,811 $19,643,168 Year Power Requirements Kws. Donlin Gold Mine Total KW KWHs. Donlin Gold Mine T-Line losses Total Installed Capecity Combustion Turbine Battory Storage System Total Capacity in KWs Generation KWH Combustion Turbine Mine Plant CosvKW Combustion Turbine Battery Storage System T-Line per Mile Capital Cost ($1000) Generation Combustion Turbine Battery Storage System Total Transmission Line Length in Miles T-Line Cost Substations. Total Fuel Storage Gallons Mine Fuel Storage Costs $/Gallon Crooked Creek Fuel Storage Costs Crooked Creek Total Fuel Olt Storage Total Capital Costs Operating Reserves, Spare Parts and Contingency 10% Total Costs Operating Costs Annual Fuel Requirements #2 Fuel Oil Gallons #2 Fue! Oil $/Galions ‘Annual Fuel Costs 8M ‘Combustion Turbine $/kWh Annual O&M Turbine T-Line @ $1000/mi Total Total O&M 40 MW Combustion Turbine Plant at Crooked Creek for 35 MW Mine Load 2008 2007 35,000 35,000 35,000 35,000 291,270,000 291,270,000 0 oO 291,270,000 291,270,000 40,000 1,000 41,000 291,270,000 291,270,000 $1,000 $1,000 $525,000 ‘$525,000 $1,000,000 $1,000,000 $34,000,000 $34,000,000 15 15 $7,875,000 ‘$7,875,000 $5,000,000 ‘$5,000,000 $12,875,000 $12,875,000 12,030,717 12,030,717 $1.28 $1.25 $15,038,307 $15,036,397 $15,038,307 $15,036,307 $61,013,307 $61,013,397 $6,191,340 $8,191,340 $68,104,736 $88,104,736 14,498,861 14,438,861 $1.53 50 $22,088,397 $22,971,033 0.0052 $1,500,041 $15,000 $1,515,041 $23,559,747 $24,486,974 35,000 35,000 291,270,000 201,270,000 40,000 1,000 41,000 291,270,000 $1,000 $828,000 12,030,717 $1.25 $15,038,307 $15,038,307 $61,013,397 $6,191,340 988,104,736 14,436,861 2009 35,000 35,000 291,270,000 0 291,270,000 40,000 1,000 41,000 291,270,000 ‘$850 $1,000 $525,000 ‘$34,000,000 $1,000,000 $34,000,000 18 $7,875,000 $5,000,000 $12,875,000 12,030,717 $1.25 $15,038,397 $15,038,397 961,013,307 $6,191,340 $68,104,738 14,436,861 2010 35,000 291,270,000 291,270,000 40,000 1,000 41,000 291,270,000 $1,000 $525,000 ‘$34,000,000 ‘$1,000,000 ‘$34,000,000 18 $7,875,000 ‘$5,000,000 $12,875,000 12,030,717 $1.25 $15,038,307 $15,038,307 $61,913,307 $6,191,340 988,104,736 14,436,001 $1.79 $25,840,300 0.0056 $1,630,135 $15,000 $1,654,135 $27,404,435 Year Interest During Constuction 0% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 415 Year Financing 0% 5% 8% Capital Cost Wh 0% 5% 8% 8M $kWh Total Cost $/kWh_ 0% 5% 8% 20 Year Financing 0% 5% 8% Capital Cost $/kWh 0% 5% 8% O&M $ikWh Total Cost $/kWh 0% 5% 8% 30 Year Financing 0% 5% 8% Capital Cost $/kWh_ 0% 5% em 08M $kWh Total Cost $/kWh O% 5% 8% Grant Funding Capital Cost O&M S/kWh Total Cost $/kWh Mine site analysisSheet3 2006 $0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 $57,162,854 2006 $3,528,550 $5,354,204 $6,678,287 $0.017 30.026 $0.032 90.081 $0,008 $0.107 $0.113 $2,646,419 $4,459,468 $5,822,143 90.013 $0,021 $0.028 90.081 90.089 90.098 $0.105 90.081 $0.081 2007 0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 $57,162,854 2007 $3,528,559 $5,354,204 $6,676,287 90.017 90.028 90.032 90.084 30.101 $0.110 90.116 $2,646,419 $4,450,468 $5,622,143 90.013 90.021 90.028 90.007 30.106 90.112 $1,764,279 $3,615,221 $5,077,812 0.008 $0.017 $0.024 90.084 $0.093 $0.101 $0.108 $0,084 90.084 2008 $0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 $57,162,654 2008 $3,528,550 $5,354,204 $6,678,287 $0.017 $0.026 $0.032 $0.087 $0.104 $0.113 $0.119 0.100 $0.109 90.115 $1,784,270 $3,015,221 $5,077,612 ‘$0.008 $0.017 $0.024 $0.087 $0.096 $0.105 90.112 $0.087 $0.087 2009 %0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 $57,162,654 2009 $3,528,559 $5,354,204 $6,678.287 $0.017 $0,026 $0.032 $0001 90.104 90.112 $0.119 $1,764,270 $3,615,221 $5,077,612 30.008 $0.017 $0.024 $0,001 $0.099 90.108 90.115 90.001 $0.001 2010 $0 $2,646,419 $4,234,271 $52,928,383 $55,574,802 $57,162,654 2010 $3,528,559 $5,354,204 $6,676,287 $0017 90.028 $0.032 90.094 90.111 $0.120 $0.127 $2,646,419 $4,450,468 $5,822,143 90.013 30.021 90.028 90.004 90.107 90.116 90.122 $1,764,279 $3,015,221 $5,077,612 30.008 $0.017 90.024 $0.004 90.103 90.112 90.110 30.094 0.094 Year Interest During Constuction O% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 15 Year Financing 0% 5% 8% Capital Cost $/kWh 0%, 5% e% O&M $kWh Total Cost $kWh 0% 5% 8% 20 Year Financing 0% 5% 8% Capital Cost $kWh 0% 5% 8% 8M $kWh Total Cost $/kWh 0% 5% 8% 30 Year Financing 0% om om Capital Cost $/kWh_ 0% 5% ow O&M SkWh Total Cost kWh O% 5% 8% Grant Funding Capital Cost 08M SxWh Total Cost $kWh 0 $3,405,237 $5,448,379 $68,104,736 $71,509,073 $4,540,316 $6,880,434 $8,593,177 $0016 $0.024 90.030 30.081 $0006 90.105 $0.110 $3,405,237 $5,738,145 $7,491,547 90.012 90.020 90.028 $0.081 $0.093 90.101 90.107 $2,270,158 $4,651,626 96,533,534 $0.008 90.016 90.022 90.007 90.103 2007 $0 $3,405,237 $5,448,379 $88,104,736 $71,509,973 $73,553,115 2007 $4,540,316 $6,880,434 $8,593,177 90.016 $0.024 $0.030 0.100 $0.108 90.114 $3,405,237 $8,738,145 $7,401,547 90.012 30.020 90.026 90.084 90.006 $0.104 $0.110 $2,270,158 4,051,828 $8,533,534 $0.008 $0.016 90.022 90.100 $0.107 30.084 90.084 $0 $3,405,237 $5,448,379 $68,104,736 $71,509,073 $73,553,115 2008 $4,540,316 98,880,434 $8,593,177 90.016 90.024 $0.030 $0.087 $0.103 $0.111 $0.117 $3,405,237 $5,738,145 $7,491,547 $0.012 $0.020 $0.026 $0.099 $0.107 $0,113 $2,270,158 $4,051,620 $6,533,534 90.008 90.016 90.022 $0.087 90.005 90.103 90.110 $0.087 $0.087 $3,405,237 $5,448,379 $68,104,736 $4,540,318 $6,880,434 $8,593,177 90.016 90.024 90.030 90.091 90.108 90.114 90.120 $3,405,237 $5,738,145 $7,491,547 90.103 90.114 90.117 $2,270,158 $4,051,626 98,533,534 90.091 90.099 $0.107 90.113 90.001 $0,091 2010 $3,405,237 $5,448,379 $68,104,736 $4,540,316 $8,880,434 $8,503,177 90.106 $2,270,158 $4,651,828 $6,533,534 $0.008 90.016 $0,102 90.110 90.117 90.004 90.004 06/10/2002 Donlin Creek Mine Altematives Fuel Inflation Factor . 4.00% ‘Turbine Heat Rate in BTU/kWh: General inflation Factor == 3.00% Tank Farm Cost per Galion Discount Rate = 3.50% Fuel cost $/Gal 30 MW Combustion Turbine Plant at Crooked Creek for 25 MW Mine Load Year 2008 2007 2008 2009 Power Requirements KWs. Dontin Gold Mine 25,000 25,000 25,000 25,000 Total KW 25,000 25,000 25,000 25,000 KWHs Donlin Gold Mine 208,050,000 208,050,000 208,050,000 208,050,000 T-Line losses 0 0 0 0 Total 208,050,000 208,050,000 208,050,000 208,050,000 Installed Capacity ‘Combustion Turbine 30,000 30,000 30,000 30,000 Battery Storage System 4,000 1,000 1,000 1,000 Total Capacity in KWs 31,000 31,000 31,000 31,000 Generation KWHs Combustion Turbine Mine 208,050,000 208,050,000 208,050,000 208,080,000 Plant CosvKW_ Combustion Turbine $950 $850 ‘$850 $850 Battery Storage System $1,000 $1,000 $1,000 $1,000 T-Line per Mile $0 $0 $0 0 Capital Cost ($1000) Generation Combustion Turbine $25,500,000 $25,500,000 $25,500,000 $25,500,000 Battery Storage System $1,000,000 $1,000,000 $1,000,000 _ $1,000,000 Total $25,500,000 $25,500,000 $25,500,000 $25,500,000 Transmission Line Length in Miles o 0 0 0 T-Line Cost 30 $0, 0 Cd Substations —_- $4,000,000 ‘$4,000,000 ‘$4,000,000 ‘$4,000,000 Total $4,000,000 $4,000,000 $4,000,000 $4,000,000 Fuel Storage Gallons Mine 8,593,370 8,503,370 8,593,370 8,593,370 Fuel Storage Costs $/Gallon ‘Crooked Creek $1.25 $1.25 $1.25 $1.25 Fuel Storage Costs Mine $10,744,712 $10,741,712 $10,741,712 Total Fuel Oli Storage $10,741,712 $10,741,712 $10,741,712 Total Capital Costs $40,241,712 $40,241,712 $40,241,712 $40,241,712 Operating Reserves, Spare $4,024,171 $4,024,171 $4,024,171 $4,024,171 Parts and Contingency at 10% Total Costs $44,265,883 $44,265,883 $44,265,883 $44,265,883 Operating Costs Annual Fuel Requirements #2 Fuel OllGalions 10,312,043 10,312,043 10,312,043 10,312,043 #2 Fuel Oil $/Gallons $1.45 $1.51 $1.57 $1.63 ‘Annual Fuel Costs $14,952,463 $15,550,562 $16,172,584 $16,819,487 Mine site analysisSheet2 6840 $1.25 $1.45 2010 25,000 25,000 208,050,000 208,050,000 30,000 1,000 31,000 208,050,000 $850 $1,000 $25,500,000 $1,000,000 ‘$25,500,000 ‘$4,000,000 ‘$4,000,000 8,593,370 $10,741,712 $10,741,712 $40,241,712 $4,024,171 $44,265,683 10,312,043 $1.70 $17,492,267 Year Power Requirements KWs Dontin Gold Mine Total KW KWHs Donlin Gold Mine T-Line losses Total Installed Capactty Combustion Turbine Battery Storage System Total Capacity In KWs Generation KWHs Combustion Turbine Mine Plant CosuKW Combustion Turbine Battery Storage System T-Line per Mile ‘Capital Cost ($1000) Generation ‘Combustion Turbine Battery Storage System Total ‘Transmission Line Length in Miles T-Line Cost Substations Total Fuel Storage Gallons Mine Total Fuel Oil Storage Total Capital Costs Operating Reserves, Spare Parts and Contingency at 10% Total Costs Operating Costs Annual Fuel Requirements #2 Fuel Oil Gallons #2 Fuel Oll $/Gallons ‘Annual Fuel Costs for 35 MW Mine Load 2006 2007 2008 35,000 35,000 35,000 35,000 35,000 35,000 291,270,000 281,270,000 291,270,000 o o J 291,270,000 201,270,000 291,270,000 40,000 40,000 40,000 4,000 1,000 1,000 41,000 41,000 41,000 281,270,000 291,270,000 291,270,000 ‘$850 $850 ‘$850 $1,000 $1,000 $1,000 %0 $0 2 $34,000,000 $34,000,000 $1,000,000 $1,000,000 0 o o $0 $0 0 ‘$5,000,000 000 ‘$5,000,000 ,000,000 000 $5,000,000 12,030,717 12,030,717 12,030,717 $1.25 $1.25 $1.25 $15,038,307 $15,038,397 $15,038,397 $15,038,397 $15,038,307 $15,038,307 $54,038,307 $54,038,397 $54,038,307 $5,403,840 $8,403,840 $5,403,840 $50,442,236 $50,442,236 $50,442,236 14,436,081 14,436,861 14,436,861 $1.45 $1.51 $1.57 $20,933,448 $21,770,786 $22,641,618 40 MW Combustion Turbine Piant at Crooked Creek 35,000 35,000 291,270,000 291,270,000 40,000 1,000 41,000 291,270,000 $850 ‘$1,000 ‘$34,000,000 $1,000,000 ‘$34,000,000 0 $0 $5,000,000 ‘$5,000,000 12,030,717 $1.25 $15,038,307 $15,038,307 $54,038,307 ‘$5,403,840 $59,442,238 14,436,861 $1.63 $23,547,282 291,270,000 291,270,000 40,000 1,000 41,000 291,270,000 $850 $1,000 ‘$34,000,000 $1,000,000 ‘$34,000,000 ° $0 $5,000,000 ‘$5,000,000 12,030,717 $1.25 $15,038,307 $15,038,397 $54,038,397 $5,403,840 $50,442,236 14,436,061 $1.70 $24,489,174 06/10/2002 Year 8M Combustion Turbine $/kWh Annual O8M Turbine T-Line @ $1000/mi Annual T-line Cost Total Total O&M Interest During Constuction 0% 5% 8% Total Capital Cost O% 5% o% Year Amortized Capital Costs 15 Year Financing 0% 5% o% Capital Cost $kWh 0% * 8% 8M SKWn Total Cost $Wh 0% 5% em 20 Year Financing 0% 5% a% Capital Cost $«Wh O% 5% a% 8M SkWh Total Cost kWh 0% 5% 8% 30 Year Financing o% 5% om Capital Cost kWh 0% * 8% 8M $KWh Total Cost “kWh os Grant Funding Capital Cost O8M SkWh Total Cost kWh Mine site analysisSheet2 0.0050 $1,040,250 0 so $1,040,250 $15,092,713 $0 $2,213,204 $3,541,271 $44,285,883 $46,479,177 $47,807,154 2006 $2,051,050 $4,477,910 $5,585,288 $0.014 $0.022 $0.027 $0.077 90.001 30.098 $0.104 $2,213,204 $3,729,609 $4,060,204 0.077 $1,475,529 $3,023,537 $4,246,587 90.007 90.015 $0.020 $0.077 90.084 $0,081 $0097 $0.077 $0.077 2007 0.0052 $1,071,458 $0 so $1,071,458 $16,622,019 $0 $2,213,204 $3,541,271 $44,285,683 $46,479,177 ‘$47,807,154 2007 $2,951,059 $4,477,910 $5,585,268 $0014 90.022 $0.027 $0094 $0.101 $0.107 $2,213,204 $3,729,609 ‘$4,000,264 soort 0.018 $0.023 $0.001 90.008 $0,103 $1,475,529 $3,023,537 $4,246,587 90.007 0.015 $0.020 $0.080 $0.087 90.094 $0.100 0.0053 $1,103,601 $0 $0 $1,103,601 $17,276,185 0 $2,213,204 $3,541,271 $44,265,683 $46,479,177 ‘$47,807,154 2008 $2,951,050 $4,477,910 $5,585,268 s0.014 $0.022 90.007 $0.108 $0.110 $2.213.204 $3,729,600 ‘$4,009,284 $0.011 90.018 $0.023 0.004 90.101 $0,108 $1,475,529 $3,023,537 $4,246,587 ‘90.007 90.015 $0.020 $0.000 90.096 90.103 $0083 $0083 2009 0.0055 $1,136,709 0 $0 $1,136,709 $17,956,197 so $2,213,204 $3,541,271 $44 265.883 $2,951,050 $4,477,910 $5,585,268 90.014 90.022 $0.027 $0.100 90.108 90.113 $2,213,204 $3,729,609 $4,069,264 $0.011 $0018 $0.023 90.097 90.104 90.110 91,475,529 $3,023,537 $4,246,567 90.007 $0.015 0.020 $0.093 90.101 90.107 2010 0.0056 $1,170,811 0 #0 $1,170,811 $18,063,077 0 $2,213,204 $3,541,271 $44,265,883 $48,479,177 ‘$47,807,154 2010 $2,951,059 $4,477,910 $5,585,288 90.014 $0.02 0.027 90.104 $0.11 90.117 $2,213,204 $3,729,609 $4,860,204 0.011 90.018 90.023 $0.100 90.108 90.113 $1,475,529 $3,023,537 $4,246,587 90.007 90.015 0.020 90.000 $0.007 90.104 90.110 $0.090 30.090 Year 08M ‘Combustion Turbine $/kWh Annual O&M Turbine T-Line @ $1000/mi ‘Annual T-line Cost Total Total O&M Interest During Constuction 0% 5% 8% Total Capital Cost O% 5% e% Year Amortized Capital Costs O&M SKWh Total Cost $kWh 20 Year Financing O% Total Cost $kWh i i 3998 993 O&M SkWh Total Cost $*kWh Grant Funding Capital Cost Total Cost $Wn 0.0050 $1,456,350 9 % $1,456,350 $22,389,708 "0 $2,072,112 $4,755,379 $59,442,236 962,414,348 $64,197,615 2008 $3,962,816 98,013,141 $7,500,178 $0.014 90.021 $0028 $0.077 90.090 90.008 90.103 $2,072,112 $5,008,269 96,538,669 90.010 90.017 0.022 9.077 90.067 90.004 90.009 $1,081,408 $4,000,143 $5,702,509 $0.007 30.014 90.020 90.077 90.084 90.091 $0.096 90.077 2007 0.0082 $1,500,041 9 90 $1,500,041 ‘$23,270,627 $2,972,112 $4,755,379 $50,442,236 $62,414,348 964,197,615 2007 $3,962,616 98,013,141 $7,500,178 $0014 90.021 0.028 90.093 90.101 90.108 $2,072,112 $5,008,289 $8,538,660 90.010 90.017 90.022 $0,090 90.097 90.102 $1,081,408 $4,060,143 $5,702,509 0.0083 $1,545,042 % 0 $1,545,042 $24,106,650 » $2,972,112 $4,755,379 $59,442,236 962,414,348 964,197,615 2008 $3,962,816 96,013,141 $7,500,178 90.014 90.021 90.026 30.007 90.104 90.109 $2,072,112 $5,008,260 $8,538,009 30.010 90.017 90.022 90.003 90.100 $0.105 $1,081,408 $4,000,143 $5,702,509 90.007 90.014 90.020 $0.000 90.007 0.103 0.0085 $1,501,393 % $0 $1,501,303 $25,138,675 $0 $2,072,112 $4,755,379 $50,442,236 962,414,548 964,197,615 2000 $9,962,816 90,013,141 $7,500,178 90.014 $0.021 $0.026 $0.100 $0.107 90.112 $2,972,112 $5,008,289 98,538,069 90.010 90.017 90.022 90.007 90.104 90.109 $1,961,408 $4,000,143 $5,702,509 90.007 $0014 90.020 $0.100 90.106 2010 0.0086 $1,639,135 wo %0 $1,630,135 $26,128,308 $0 $2,972,112 $4,755,370 $50,442,236 $62,414,348 904,197,615 2010 $3,062,816 96,013,141 $7,500,178 90.014 $0.021 90.026 90.103 90.110 90.115 $2,972,112 $5,008,289 $6,538,660 90.010 90.017 90.022 $0.100 90.107 90.112 $1,081,408 $4,060,143 $5,702,509 90.007 90.014 $0.020 $0.007 90.104 0.109 08/10/2002 Fuel Inflation Factor . General inflation Factor == Discount Rate . Doniin Gok! Mine Total KW KWHs Doniin Gold Mine T-Line losses Total Installed Capacity Combustion Turbine Battery Storage System Total Capacity in KWs Generation KWHs ‘Combustion Turbine Mine Plant CosvKW Combustion Turbine Battery Storage System T-Line per Mile ‘Capital Cost ($1000) Generation Combustion Turbine: Battery Storage System Total Transmission Line Length in Miles T-Line Cost Substations Total Fuel Storage Gallons Mine Fuel Storage Costs $/Gallon Crooked Creek Fuel Storage Costs Mine Total Fue! Oll Storage Total Capital Coste Operating Reserves, Spare Parts and Contingency at 10% Total Costs Operating Costs Annual Fuel Requirements #2 Fue! Oil Gallons #2 Fuel Oil $/Gallons ‘Annual Fuel Costs Yoar 8M ‘Combustion Turbine $/kWh Annual O&M Turbine T-Line @ $1000/mi Annual T-line Cost Total Total O&M Mine site analysisSheets Donlin Creek Mine Alternatives 4.00% 3.00% 3.50% for 25 MW Mine Load 2008 2007 25,000 25,000 25,000 25,000 208,050,000 208,050,000 ° 0 30,000 30,000 1,000 1,000 31,000 31,000 208,050,000 208,050,000 $850 $850 $1,000 $1,000 so 0 $25,500,000 $25,500,000 $1,000,000 $1,000,000 ° ° so $0 ‘$4,000,000 $4,000,000 ‘$4,000,000 $4,000,000 8,503,370 6,593,370 $1.25 $125 $10,741,712 $10,741,712 $10,741,712 $10,749,712 $40,241,712 $40,241,712 $4,024,171 $4,024,171 $44,265,083 $44,285,683 11,457,828 11,457,626 $1.45 $1.51 $16,813,648 = $17,278,402 2008 2007 0.0050 0.0052 $1,040,250 $1,071,458 $0 $0 $0 $0 $1,040,250 $1,071,458 $17,654,098 $18,349,859 Turbine Heat Rate in BTU/KWh 7600 Tank Farm Cost per Galion $1.25 Fuel cost $/Gal $1.45 30 MW Combustion Turbine Plant at Crooked Creek 2008 2008 2010 25,000 25,000 25,000 25,000 25,000 25,000 208,050,000 208,050,000 208,050,000 30,000 30,000 30,000 1,000 1,000 1,000 31,000 31,000 31,000 208,050,000 208,050,000 208,050,000 ‘$850 $850 ‘$850 $1,000 $1,000 $1,000 so 0 0 ‘$1,000,000 $1,000,000 $1,000,000 $25,500,000 $25,500,000 $25,500,000 ° $0 $4,000,000 $4,000,000 8,599,370 8,593,370 8,583,370 $1.25 $1.25 128 $10,741,712 $10,741,712 $10,741,712 $10,741,712 $10,741,712 $10,741,712 $40,241,712 $40,241,712 $40,241,712 $4,024,171 $4,024,171 $4,024,171 $44,205,083 $44,265,683 $44,285,883 11,457,826 11,457,826 11,457,626 $1.57 $1.63 $1.70 $17,909,538 «$16,688,319 = $ 852 2008 2009 2010 0.0053 0.0055 0.0086 $1,103,601 $1,136,709 $1,170,611 $0 0 #0 $0 $0 %0 $1,103,601 $1,196,708 $1,170,811 s 73,199 $19,825,029 $20,808,663 Year Power Requirements KWs Donlin Gold Mine Total KW KWHs Donlin Gold Mine T-Line losses Total Installed Capacity Combustion Turbine Battery Storage System Total Capacity in KWe Generation KWHs Combustion Turbine Mine Plant CosvkW Combustion Turbine Battery Storage System T-Line per Mile Capital Cost ($1000) Generation Combustion Turbine Battery Storage System Total ‘Transmission Line Length in Miles T-Line Cost Substations Total Fuel Storage Gallons Mine Fue! Storage Costs $/Gallon ‘Crooked Creek Fue! Storage Coste: Mine ‘Total Fuel Oli Storage Tota! Capital Coste Operating Reserves, Spare Parts and Contingency at 10% ‘Total Coste Operating Coste Annual Fuel Requirements #2 Fuel Oil Gallons #2 Fuel Oil $/Galions Annual Fuel Coste Year aM Combustion Turbine $/kWh Annual O&M Turbine T-Uine @ $1000/mi ‘Annual Tine Cost Total Total O&M for 35 MW Mine Load 2006 2007 35,000 35 000 35,000 38,000 201,270,000 201,270,000 0 ° 291,270,000 291,270,000 40,000 40,000 1,000 1,000 41,000 41,000 291,270,000 291,270,000 $850 $850 $1,000 $1,000 $0 0 $1,000,000 ‘$1,000,000 ‘$34,000,000 $34,000,000 ° ° 90 0 $5,000,000 ‘$5,000,000 $5,000,000 ‘$5,000,000 12,030,717 12,030,717 $128 S128 $15,038,997 $15,038,397 $15,038,907 $15,038,397 $54,038,397 $54,038,397 $5,403,840 $5,403,640 $50,442,238 $80,442,236 16,040,957 16,040,057 $1.45 $1.51 $23,250,387 $24,189,762 2008 2007 0.0050 0.0052 $1,456,350 $1,500,041 0 $0 0 0 $1,456,350 $1,500,041 $24,715,737 $25,689,803 40 MW Combustion Turbine Plant at Crooked Creek 2008 2008 2010 35,000 35,000 35,000 35,000 35,000 35,000 291,270,000 291,270,000 281,270,000 ° o o 291,270,000 291,270,000 291,270,000 40,000 40,000 40,000 1,000 1,000 1,000 41,000 41,000 41,000 291,270,000 281,270,000 281,270,000 $850 $850 $850 ‘$1,000 $1,000 $1,000 0 $0 $0 $34,000,000 $34,000,000 $34,000,000 $1,000,000 $1,000,000 $1,000,000 $34,000,000 $34,000,000 $34,000,000 ° ° ° ~ » $0 $5 000 000 ‘$5,000,000 ‘$5,000,000 ‘$5,000,000 ‘$5,000,000 ‘$5,000,000 12,030,717 12,030,717 12,030,717 $1.25 $1.28 $1.28 $15,036,307 $15,038,907 $15,036,307 $15,036,307 $15,036,397 $15,038,307 $54,036,307 $54,038,397 $54,036,397 $5,403,840 $5,403,840 $5,403,640 $50,442,296 $59,442,296 $50,442,236 16,040,957 16,040,957 16,040,057 $1.57 $1.63 $1.70 $25,187,353 $28,163,647 $27,210,193 2008 2008 2010 0.0053 0.0055 0.0056 $1,545,042 $1,501,393 $1,630,135 0 #0 $0 so 30 $0 $1,545,042 $1,501,393 $1,639,135. $26,702,305 $27,755,040 $28,649,328 Your Interest During Constuction 0% 5% 8% Total Capital Cost 0% 5% 8% Year Amortized Capital Costs 15 Year Financing o% 5% o% Capital Cost $/kWh 0% 5% o% O&M SkWh Total Cost $/kWh 0% 5% 8% 20 Year Financing 0% 5% 8% Capital Cost kWh 0% 5% o% O&M $kWh Total Cost $/kWh 0% * 8% 30 Year Financing 0% 5% o% Capital Cost $/kWh_ 0% 5% o% O&M SkWh Total Cost $/kWh 0% 5% o% Grant Funding Capital Cost O&M S/KWh_ Total Cost /kWh Mine site analysisSheet4 0 $2,213,204 $3,541,271 $44,265,883 $48,479,177 $47,807,154 2008 $2,051,050 $4,477,910 $5,585,268 $0014 $0.022 $0.027 $0,085 $0.099 $0,106 90.112 $2,213,204 $3,729,600 $4,089,264 90.011 $0.018 $0.023 $0.085 90.095 $0.103 90.108 $1,475,529 $3,023,537 $4,246,587 $0.007 90.015 $0.020 $0.092 90.008 $0.105 ° 90.085 $0.085 2007 0 $2,213,204 $3,541,271 $44,285,883 $46,479,177 $47,007,154 2007 $2,951,059 $4,477,910 $5,585,208 0.014 90.022 $0.027 $0.102 90.110 90.115 $2,213,204 $3,729,609 $4,069,264 $0011 90.018 30.023 90.099 90.106 $0.112 $1,475,529 $3,023,537 $4,246,587 ‘$0.007 $0.015 $0.020 30.088 0 $0.088 90.088 2008 so $2,213,204 $3,541,271 $44,265,683 $46,479,177 ‘$47,807,154 2008 $2,951,050 $4,477,910 $5,585,288 $0.014 $0.022 $0.027 $0.106 $0.113 90.119 $2,213,204 $3,729,609 $4,060,264 $0.011 $0.018 $0.023 $0.092 $0.102 $0.110 $0.115 $1,475,529 $3,023,537 $4,246,587 $0,007 90.015 $0.020 $0,082 $0.009 $0.106 $0.112 $ 88. 2009 so $2,213,294 $3,541,271 $44,205,683 $46,479,177 ‘$47,807,154 2009 $2,951,059 $4,477,910 $5,585,268 $0.014 $0.022 $0.027 90.005 90.109 90.117 90.122 $2,213,204 $3,729,609 $4,869,264 90.011 $0.018 $0.023 $0,108 90.113 $0119 $1,475,529 $3,023,537 $4,248,587 $0.007 90.015 $0.020 $0.095 $0.102 90.110 $0.116 g Ss 0 $2,213,204 $3,541,271 $44,265,683 $46,479,177 $47,807,154 2010 $2,951,059 $4,477,910 $5,585,268 $0.014 0.022 90.027 90.113 $0.121 $0.128 $2,213,294 $3,729,609 $4,060,264 $0011 $0.018 $0.023 $0.090 $0.110 90.117 $0.122 $1,475,529 $3,023,537 $4,248,587 $0.007 90.015 ‘$0.020 30.099 90.108 90.114 30.119 8 33. 15 Year Financing 0% 3% 8% Capital Cost $/kWh 0% 5% 8% O&M $/KWh Total Cost $/kWh O% 5% 8% 20 Year Financing o% 3% % Capital Cost $/kWh 0% 5% o% 8M $kWh ‘Total Cost $/kWh o% 5% 8% 30 Year Financing 0% 5% 8% Capital Cost $kWh 0% * 8% O&M $KWh ‘Total Cost $/kWh 0% * 8% Grant Funding Capital Cost 8M $/kWh Total Cost $/kWh so $2,072,112 $4,755,379 $59,442,236 $62,414,648 964,197,615 $0.098 $0.108 90.111 $2,972,112 ‘$5,008,289 $8,538,069 $0.010 90.017 $0.022 $0.085 $0.09 90.102 90.107 $1,081,408 $4,080,143 $5,702,509 $0.007 90.014 $0.020 90.099 90.104 8 83. 2007 $0 $2,072,112 $4,755,379 $59,442,236 $02,414,348 $64,197,615 2007 $3,962,616 $8,013,141 $7,500,178 $0.014 $0.021 $0.026 $0,102 $0,109 90.114 $2,972,112 ‘$5,008,289 $8,538,069 $0.010 $0.017 $0.022 $0.088 $0008 90.105 30.111 $1,981,408 $4,000,143 $5,702,509 ‘$0,007 90.014 90.020 90.102 $0.108 0 $2,072,112 $4,755,379 $50,442,236 $62,414,948 $64,197,615 2008 $3,062,816 $8,013.141 $7,500,178 90.014 $0,021 $0,028 ‘$0.092 $0,105 90.112 90.117 $2,972,112 $5,008,269 $6,538,000 $0.010 $0.017 $0.022 $0.092 $0.102 $0.10 90.114 $1,981,408 $4,080,143 $5,702,509 $0.007 90.014 $0.020 90.098 90.106 90.111 $0 $2,972,112 $4,755,379 $50,442,236 $62,414,348 $64,197,615 2009 $3,962,816 $6,013,141 $7,500,178 $0014 90.021 0.028 90.109 90.1168 $0.121 $2,972,112 $5,008 269 $6,538,669 90.010 90.017 $0,022 90.095 $0,105 90.112 $0.118 $1,981,408 $4,080,143 ‘$5,702,509 $0.007 90.014 $0.020 90.095 $0,102 90.108 90.115 2010 $0 $2,972,112 $4,755,370 $50,442,236 $62,414,348 $64,197,615 2010 $3,962, $8,013,141 $7,500,178 $0.014 90.021 90.028 90.099 90.113 90.120 $0.128 $2,972,112 $5,008,289 96,538,669 $0.010 $0.017 $0.022 $0.009 90.109 90.116 90.121 $1,081,408 $4,080,143 $5,702,509 ‘$0,007 90.014 ‘$0.020 90.108 90.113 90.119 08/10/2002 C.2. Crooked Creek, Alaska Cogeneration Project, prepared by Precision Energy Services, Inc. 11 PRES Friston CROOKED CREEK, ALASKA COGENERATION PROJECT FUEL OIL #2 — FIRED TURBINE WITH HEAT RECOVERY STEAM GENERATOR AND STEAM TURBINE MAY, 2002 Prepared By: Precision Energy Services, Inc. Project Development Division CROOKED CREEK Page | of 16 IDES =: <a genvices INC. INTRODUCTION TC\LI "INTRODUCTION This report has been prepared to be used as a part of a feasibility study of a cogeneration power plant intended to be developed for the supply of electric power for a new mine to be located near Crooked Creek, Alaska. In addition, the plant will have the capability of supplying heat to the oil storage tank farm and local buildings and installations. The goal of this report is to provide the project developers sufficient information to identify a cogeneration option that will supply power and heat at a competitive cost to the new mine. Permitting issues relating to the construction and operation of the power plant have been signaled here to make the developer aware of the possible requirements. The system that has been evaluated herein consists of a combustion turbine fired with distillate oil #2, one heat recovery steam generator, one steam turbine and one each electric generator driven by respective turbines. A system in which both turbines drive one generator is significantly more complicated; the cost advantage, if any, is very small in comparison with the degree of plant complication. The system will also include a system, for the supply of hot water for local heating of the fuel oil storage facilities and buildings, consisting of steam condensing heat exchange station, in which saturated steam extracted from the steam turbine will condense and give off the latent heat of vaporization/condensation to heat the water circulating in the outside heating system. The system will be engineered and operated according to the latest developments in the District Heating technology being promoted by the International Energy Agency. Distribution piping from the heat exchanger station to local receivers is not included in the analysis. For the evaluations included in this Report, we have considered combustion turbines supplied by Alstom Power (EGT) Cyclone Turbine + Generator Package, Solar Turbine Titan 130 Turbine and Generator and GE 10-60 Hz Turbine + Generator Package operating at 100% capacity. We requested budgetary pricing from Mitsubishi Power Systems for a cogeneration system based on the MF-111B turbine; however, by the time of writing this Report, we have not received a quote. Therefore the following feasibility evaluation is based on the Solar and Alstom and GE packages. The turbines being supplied by the three companies represent the state of art in liquid fuel turbine combustion technology including NOx control during the combustion process. Utilization in this project of the combined cycle cogeneration arrangement with partial heat supplied to a local district heating system enables the facility to achieve thermal efficiencies in the range of 53%, which is practically not achievable by a diesel engine-based generating plant. The heat rate (thermal input in fuel to produce one kW of electric or equivalent power) of this plant will be in the range of 6,500 Btu/kW-hr (with local heating) and 7,410 Btu/kW-hr (without local heating). Also the financial results of the cogeneration plant indicate a positive feasibility. The net cost of generating power is in the range of $80.78 to $97.92 per MW-hr depending on the length of debt financing and whether or not the plant will be supplying local heating. CROOKED CREEK Page 2 of 16 PRES Firctome 1. INPUT / UT DATA The following table summarizes the Input information (required power and heat and other data) as well as output data as provided by three vendors. NA data not available NI Not included PBO To be provided by others (than the main vendor) * NAp data not applicable Data provided by vendor; all other data — calculated or from generally available sources as’d assumed Table 1, Input / Output Data Fuel data #2 Distillate oil, net HV Btu/Ib 17,855 Btu/gal 128,869 Density Ib/gal dae Vendor / System r Solar Alstom GE Required electric output, net KW 20,000 Parasitic power - turbine (fuel pump, ...) |KW a 60 Parasitic power - steam system KW 283 Required electric output, gross KW 20,310 20,322 20,343 CT Turbine | CT turbine output KW 13,613 11,465 14,513 Turbine heat rate Btu/kW-hr 10,260 Heat input Btu/hr 137,494,000 119,316,000} * 123,113,000 Fuel input Ib/hr 7,701 * 6,804 * 6,764 gph 1,067 942 937 Combustion air supply lb/hr 383,350 310,540 379,200 Turbine output converted to thermal units | Btu/hr 46,449,000 39,119,000 49,518,000 Heat content in combustion gases Btu/hr 91,045,000 80,197,000 73,595,000 — Heat recovery steam generator (HRSG) PBO PBO PBO Products of combustion Ib/hr * 390,272 * 317,600 * 385,900 | Turbine exhaust temperature °F 960 1,003 * 899 Heat losses in system (convection, radiant, h 5 4 boiler blowdown, ), including with flue gas = 2,348,000 2,068,000 1,898,000 HRSG system exhaust temperature SE 265 259 * 247 Heat losses with flue gas in exhaust Btu/hr 16,293,000 12,845,000 14,493,000 Heat available for steam generation Btwhr 72,404,300 65,284,000 57,204,300 Superheated steam parameters SF 700 * 754 = 756 Psig 600 * 620 * 637 Superheated steam generation lb/hr 60,970 53,550 57,140 DH + DA steam flow (for corrected flow) | Ib/hr 19,390 22,290 20,382 CROOKED CREEK Page 3 of 16 IDE fmt raa SERVICES INC. Table 1, continued Vendor / System Solar Alstom GE Power Generation in both Cycles Power generation with DH and DA steam | kW 1,053 1,210 1,110 Power generation in condensing cycle kW 4,250 3,196 3,758 Power generation with condensing & exirection sina (total) kW 5,303 4,406 4,868 Total power generation kW 18,917 15,871 19,381 Power generation shortage kW 1,393 4,462 962 Equivalent amount of superheated steam Ib/hr 19,500 65,390 13,470 required Exgevalent SET speeaiigl immpart necquines Stk lee 25,176,000| 84,683,000} —_‘17,445,000 additional firing Equivalent GROSS thermal input required |. ne 31,067,000] 103,481,000} 21,463,000 in additional firing Equivalent fuel input for duct burning lb/hr 1,740 5,796 1,202 gal/hr 241 803 167 Total fuel demand gal/hr 1,308 1,745 1,103 ae : : 5 Pesneics Seasing (DE) enexpy (inclnden S97 | ra tie 10,000,000 10,000,000 —_10,000,000 efficiency) Converted to equivalent power units KW-hr 2,930 2,930 2.930 Total equivalent power kW-hr/hr 23,240 23,263 23,273 Performance Heat rate I on electric power generation Btu/kW-hr 8,300 10,960 7,110} Heat rate IT on equivalent power Btu/kW-hr 7,250 9,580 6,210 Heat rate III on electric power generation in Btu/kW-hr 10,100 10,410 8.480 CT turbine | Plant efficiency I on electric power 46.9% 45.4% 53.7% | Plant efficiency II on equivalent power 47.0% 35.6% 55.0% | | | Total fuel demand per day gal/day 31,400 41,900 26,650 | Total fuel demand for 9 months bbl 201,840 269,250 171,280 | The fuel to be utilized at the plant is #2 Distillate oil as per ASTM Standard D396. CROOKED CREEK Page 4 of 16 IDE! a SERVICES INC. DESCRIPTION OF THE POWER PLANT T "SUMMARY AND CONCLUSIONS The Power Plant will include the following systems: _ Fuel receiving and storage tanks. One liquid fuel combustion turbine with directly driven electric generator. One heat recovery steam generator including economizer with ducting and exhaust stack. Steam turbine with directly driven electric generator. Steam condenser with cooling tower and cooling water circulating pumps. Switch gear and substation. Feed water chemical treatment, deaerator and pumps. Instrumentation and controls, central control room and motor control center. Sey SVS 2 Maintenance shop with tools. = S The plant will be housed in appropriate buildings. The buildings will also include locker and lunchroom facilities. Fuel Receiving and Storage The plant will consume estimated 27,000 gallons of fuel per day. The fuel receiving and storage system should be capable of storing fuel supply for 9 months operations; that is 172,000 barrels. The fuel will be stored in appropriate thermally insulated tanks. The tanks and fuel piping will be winterized and heated, as necessary. The fuel receiving and storage system will be equipped with fuel pumping equipment for unloading from barges and separate pumps for the delivery of the fuel to the combustion turbine and other burners at the plant. All fuel piping will be thermally insulated and heat traced. The system will include also a vapor recovery and fuel loading hermetization system for prevention of emissions of fuel vapors and recovery. Combustion Turbine For the purposes of this study, budget type proposals were requested from major manufacturers/suppliers of small power combustion turbines. Those include: ALSTOM Power - Solar Turbines - GE Aero Energy Products - Mitsubishi Heavy Industries, Combustion Turbines Following initial evaluation of the materials received from vendors, the Mitsbishi options was eliminated from further evaluation due to lack of sufficient data. Information packages of the respective CT turbines are attached to herein. A summary of important data is presented in the Input/Output Data Table (the I/O Table). The CT turbines are supplied by the respective vendors with the scope listed in the following summary. Some minor differences between suppliers do exist, CROOKED CREEK Page 5 of 16 IPE Frise me however, we have done our best to reduce the differences to an absolute minimum that would not impact the performance of the system. Engine Core Engine Instrumentation Air inlet casing temperature thermocouples Compression section discharge temperature thermocouples Low pressure turbine exhaust outlet temperature thermocouples Engine bearing temperature monitoring Rotor speed probe Accelerometer type vibration probe on engine casing Non-contacting vibration probes in turbine radial and thrust bearings Key phasor Turbine compressor discharge pressure transmitter Tindéchase'- fabricated steel construction, designed for multi-point mounting to carry the gas turbine, gearbox, generator, and auxiliaries; including an integral lube oil tank constructed from carbon steel, and gland plate in underbase to facilitate cabling for electrical devices Lube Oil System mounted on a skid. Integral lube oil system serving the turbine, gearbox and generator. Main pump, gearbox driven Auxiliary lube oil pump with AC motor drive Emergency lube oil pump with DC motor On-skid lube oil piping, stainless steel. Lube oil pressure transmitter and switch Lube oil supply temperature thermocouple and switch Lube oil tank temperature thermocouple Lube oil tank low level switch and annunciation One (1) lube oil tank immersion heater Duplex-type 10 micron lube oil filter, fitted with differential pressure switch. Lube Oil Breather System with low pressure oil mist eliminator breather system constructed of carbon steel for oil mist reduction Oil Cooler with simplex fin-fan lube oil cooler suitable for an ambient temperature up to 95°F Non-return valves for lube oil cooler pipe work. Engine Auxiliaries Turbine compressor cleaning system for hot and cold water wash Aluminum instrument bodies Identification and warning labels Stainless steel on-skid pipe work with stainless steel compression fittings Breather from lube oil tank and engine casing, piped to the roof of the acoustic enclosure Start System with variable frequency drive starting system DLE Liquid Fuel System Liquid fuel pump, AC motor driven Duplex type, 10 micron, liquid fuel filter complete with differential pressure transmitter On-skid fuel piping in stainless steel downstream of filter Shut-off valves Liquid fuel grounding Independent control of primary, secondary and tertiary liquid fuel flows Off-skid shut off and thermal relief valves supplied loose CROOKED CREEK Page 6 of 16 me ae senvices INC. ir Intake System comprised of: Pulse-type self-cleaning combustion air intake filter, constructed of painted carbon steel, with simple support structure and access ladder - Combustion air intake silencer, constructed from painted carbon steel, designed for overall sound attenuation to 85 dB(A) at 3 ft (1m) measured at 5 ft (1.5 m) above grade - Expansion joint Transition duct Exhaust System Diffuser constructed from stainless steel Acoustic Enclosure fitted over the turbine, gearbox and generator, bolted to the underbase, for average sound attenuation to 85dB(A) SPL at 3ft measured at 5ft (1.5m) above grade; with internal lighting, carbon steel construction with doors and removable side panels for personnel/maintenance access. Ventilation System of the Enclosure with ventilation inlet and outlet dampers and inlet and outlet silencers, constructed of painted carbon steel, designed for an overall noise level of 85dB(A) SPL at 3ft, measured at 5 ft above grade, and Simplex AC electric motor driven ventilation fan designed for Class 1 Division 2 Group D area classification, and a maximum for ambient temperature up to 95°F (35°C) and ventilation air flow detector Fire and Gas System - Four (4) ultra-violet flame detectors - Two (2) heat detectors - Two (2) gas detectors - Twin shot CO) fire protection system with provision for weighing the CO2 bottles to monitor charge - Audible and visible alarms for extinguishant release - Suitable for Class 1 Division 2 Group D area classification Gearbox System - Epicyclic speed reducing gearbox with an output shaft speed of 1800 rpm with accelerometer vibration probe mounted on the gearbox casing; designed for turbine rated core - Output Coupling - dry diaphragm coupling with torque-limiting device between gearbox and AC generator - Coupling Guard constructed from non-sparking material AC Generator and Electrical Equipment . - 1800 rpm, 13.8 kV, 3 phase, 4 wire, 4 pole, 60 Hz, 0.8 power factor, salient pole brush-less AC generator, nominally rated to match the turbine output at 59°F (15°C) - Open ventilated - Generator bearing temperature detectors - Class ’F’ insulation with class ’F’ total temperatures - Stainless steel junction boxes - Classified for a non-hazardous area Control System The basic equipment package is supplied with a free-standing control panel suitable for mounting in an indoor, non-hazardous area. The control system features an integrated electronic fuel management system with a PLC based programmable sequencer, vibration monitor, digital meter, digital generator protective relay module and a desktop computer. Alarm and shutdown events are displayed on the HMI automatically. An Ethernet TCP/IP EGD or RS485 Modbus Port is provided to transmit unit conditions (status, pressures, temperature, etc.) to the customer's distributed control system. A printer can be furnished to provide hard copy records. Power for the control panel is provided by a dedicated 24V DC lead acid battery system with dual 100% capacity chargers. The control system includes the following: : Turbine sequencing and protection CROOKED CREEK Page 7 of 16 BRES =: oe annvicce INC. - Fault monitoring - Intelligent display - Annunciation - Gas turbine speed control - Temperature monitoring - Standard turbine casing vibration monitoring - Generator bearing temperature monitoring - Monitoring of accelerometer on gearbox - Transient logging package for fast data logging - Interlocks for standard fire and gas monitor - Automatic voltage regulator - Automatic and manual synchronizing facility with check synchronizer - Generator metering equipment and electrical protection Electrical Accessories - All on-package electrical devices to be Class 1 Division 2 Group D area classification - All on-package control cabling - Stainless steel junction boxes, located on external surface of gas turbine generator package - Galvanized carbon steel cable tray - Integral grounding protection - Emergency ’stop’ push-button on turbine underbase - Battery Cabinet constructed of carbon steel, located off main skid Heat Recovery Steam Generator For this study three quotes of HRSG were obtained: - Deltak Boilers (supplied by Alstom Power) - ABCO Boilers - ENERCOR The boilers may be procured separately; neither vendor included in their proposals’ scope of supply the HRSG. The Deltak boiler should be procured through Alstom. All three companies specialize in this type of steam generation systems. Our experience with ABCO and Deltak indicate that the quality of their products and professionalism of their engineering is amongst the highest in the industry. In all three cases additional firing is needed. The I/O Table show calculated requirements for duct firing. The HRSG system will include: - Expansion joint to HRSG - Transition duct, internally insulated - Firing duct with in-duct burner - Deltak boiler with built-in removable superheater - Economizer - Walkways & Platforms - Trim to ASME Section | Jurisdiction = HRSG Control module with outputs supplied to the Central Control Processor - Interconnecting piping - Single Blade Diverter CROOKED CREEK Page 8 of 16 IPE: — SERVICES INC. Outlet and bypass stack & associated structure Valves and Controls - Boiler feedwater regulator - Water column assembly with gauge glass, electrical lock-out and auxiliary switches for high and low level alarms, and high and low level shut downs. - Three element feedwater control system including water level transmitter, steam flow element and water flow element. - Water and steam pressure gauges - Water and steam thermometers - Exhaust gas temperature and pressure indicators - Main steam non-return valve - Main steam stop valve - Feedwater stop-check valve - Continuous blow-down tandem valve set - Intermittent Blow-off tandem valve set - Water column and gauge drain valves - Superheater drain and vent valves - Economizer drain and vent valves - Chemical feed valve - Safety valves per ASME Code c/w silencers. Steam Turbine and Generator System The Steam Turbine and Generator system will be included in the Power Plant typically consisting of: Turbine unit with condensing steam exhaust and one back pressure steam extraction outlet with non-return valves for district heating and de-aerator. The unit is provided with axial exhaust orientation, for direct connection to the condenser flange. Emergency stop valve and non-return valves are included as required. Required piping, insulation blankets, sheet metal lagging Generator, 13.8 kV, 60 Hz, 3600 rpm, 0.8 PF with brush-less excitation and coolers sized for water temperature 85°F. Generator shaft is monitored for vibrations and grounded. RTDs are provided in each phase windings and in air ducts and bearings. Water leak detection is provided. Coupling flange is integrally forged. The CT Lubricating Oil System will supply all lubricating oil needs of the steam turbine. It will include interconnecting piping and oil coolers sized for water temperature 85°F. Speed Reduction gear; parallel shaft design in compliance with AGMA 421.06. Shaft vibration is monitored. RTDs are installed in bearings. Complete stand-alone digital control system handling all required turbine and generator controls (closed and open loop) and monitoring instrumentation (power output, pressures, temperatures, vibrations, etc.) of the steam turbine and generator unit. The control system includes a coordinating controller plus separate control units for the turbine governor function, steam turbine safety trip functions and generator voltage regulator functions. Generator protection relays, if required. All man-machine interface, as well as all measurements, status and alarm displays are handled from the Plant operator station with color monitor, keyboard and trackball, supported by an event and alarm printer. Unit is built for indoor installation with noise attenuation to 85 dBA. CROOKED CREEK Page 9 of 16 PDE PRECISION EMERGY SERVICES INC. Steam surface condenser with two feedwater circulating, liquid ring vacuum pumps. Each pump at 100% capacity. The condenser is built of 304L stainless steel tubing and tubesheets and coal tar epoxy coated water boxes. The surface condenser quote was provided by Alstom Power. Cooling tower — two cell; fiberglass structure, stainless steel connecting hardware, heavy duty PVC film pack fill, two fans with drive, fire retardant FRP fan cylinders for velocity recovery. The cooling tower quote was provided by Psychrometric Systems, Inc. Feed water chemical treatment and deaerator. The necessary system for the plant will be provides. Air pollution control system Due to the character of the project, the air pollution control system will be minimal. Two types of pollutants from the plant require discussion because they may possibly present a control requirement: - Carbon monoxide (CO) and Volatile Organic Compounds (VOC) - Nitrogen oxides (NOx) Combustible CO and VOC are generated in the turbine’s combustion chamber as intermediate products of incomplete combustion. At sufficient residence time, they convert further to final products of combustion — CO, and H20. Due to extremely short residence time in the turbines’ combustion volume or quenching caused by entering cooling air, the products of incomplete combustion escape the combustion zone. The same conditions that bring about generation of excessive CO and VOC are also responsible for high NOx generation rates. The diffusion flame in the combustion zone of a CT turbine, resulting from mixing there of the fuel and air, is highly non-uniform operating over a broad range of temperatures between 2000 and 4000°F. In such conditions NOx is created because of the high temperatures and uneven temperature distribution that tends to stabilize the products of reactions between nitrogen and oxygen. At high turbine loads the NOx generation increases. A significant factor in this process is also the use of liquid fuel, which has to be finely atomized to promote better combustion. Solar Turbines developed a process/system SoLONOx, which reduces both types of pollutants. The fuel injector of the SoLoNOx system includes a pre-mix duct where the fuel is injected into a swirling air stream. This produces a well pre-mixed fuel air mixture that burns with a uniform flame pattern at about 2800°F. Formation of NOx is strongly impeded due to the absence of high reaction temperature zones. Also CO and VOC emissions are reduced due to sufficiently high temperature and very good premixing of the components. The GE-10 turbine will be supplied with the XONON technology (see attached information), which will bring NOx emission levels of the liquid fuel application to acceptable levels without steam or water injection. The main components of this combustion system are the pre-burner, the main fuel injector, the catalytic reactor, and the post-catalytic reaction liner. The CO and VOC pollutants will be also controlled by additional combustion with a duct burner with sufficient residence time (min. 0.6 seconds) provided by the duct to the heat recovery steam generator, where CROOKED CREEK Page 10 of 16 IES PRECISION ENERGY SERVICES INC. both the heat remaining in the combustion gases exiting the CT turbine and the heat added in the duct burner will be recovered for steam raising. The Alaska Department of Environmental Conservation (Janet 907 465-5122) determines allowable NOx emissions based on the turbine’s heat rate using the following formula for a CT turbine installation at total heat release in excess of 10 MM Btu/hr: % vol. = 0.015 x 14.4 / kJ/W-hr ppm vol. = 0.216 x 10,000 / (Heat rate [Btu/kW-hr] x 1.055/1000) The respective numbers for expected emissions are presented in the following table: Table 2, NOx generation rates calculated using Alaska DEC method Solar Alstom GE Btu/ Btu/ Btu/ kW-hr Ppm vol. kW-br Ppm vol. kW-br Ppm vol. Heat rate I on electric power generation 8,300 247| 10,960 187 7,110 288 Heat rate II on equivalent power 7,250 282 9,580 214} 6,210 328 Heat rate III on electric power generation in CT turbine 10,100 203| 10,410 197 8,480 241 The values in the column titled ppm vol. are very high, especially when compared to the actual capabilities of modern CT turbines. The following table shows values based on the NSPS standard of 0.15 Ib of NOx per million Btu (MM Btu). Table 3, NOx generation rates using NSPS Standard Solar Alstom GE Ib/hr 25 33 Deh SCFH NOx 209 109 118 SCFH flue 5,157,300 4,690,000 5,090,000 Ppm vol. 40 23 23 |Ppm vol. corrected to 11% O) 53 57 34 Basically, the State of Alaska requires application of BACT (Best Available Control Technology). The state will require information from the CT turbine manufacturer to determine that the turbine to be installed at the site in Alaska is state of art technology. As a result, we expect that the State will not require the application of any additional NOx and CO control means. Instrumentation and controls, central control room and motor control center The Power Plant will be equipped with all instrumentation and controls necessary for trouble-free operation of the Plant. The controls and instrumentation are listed above with the respective equipment systems. The CCR (central control room) will include an operator station with color monitor, keyboard, track ball and event and alarm printers. A motor control center for the plant will be provided in a separate room of the main building. The Control philosophy of the system is such that the Cogeneration Plant should operate automatically requiring very little operator input. The input shall be required only in off-spec or emergency situations. At CROOKED CREEK Page 11 of 16 PRECISION ENERGY SERVICES INC. normal operations, the system operates based on inputs from the various temperature, pressure, flow and other measuring devices. Occasional intervention of the operator will be required to set operating conditions if these have to be changed; for instance: setting changes of the local heating system as a result of significant weather changes, changes of turbine settings as a result of long-term (longer than 24 hours) change in power demand, and so on. Local Heating System The plant will include provision for connecting to a local heating system. It will include a heat exchanger for heating water circulating between the plant and the local heat receivers. The circulating water will be heated partially with heat of condensation in the steam turbine’s condenser and partially with extracted steam. At the maximum demand for heat, the plant can supply to the heating system an equivalent of up to 12 MM Btu/hr. PES has experience in engineering heat exchanger stations for district heating systems. The piping system to the heat receivers is not included in the Power Plant cost. CROOKED CREEK Page 12 of 16 PES Fiicsome Table 4, Feasibility Analysis. Input Data see Feasibility Evaluation on the following pages spreadsheets The feasibility analysis is based on Solar Turbines supplies. Table 5, Feasibility Analysis. Output Data = see Feasibility Evaluation on the following pages spreadsheets Table 6, Simplified Feasibility Analysis of Diesel-based Generation Plant 20 MW net output see Feasibility Evaluation on the following pages spreadsheets CROOKED CREEK Page 13 of 16 PDE! = SERVICES INC. CROOKED CREEK, ALASKA 20 MW ELECTRIC COGENERATION PROJECT FINANCIAL ANALYSIS, SPREADSHEETS JUNE, 2002 Prepared By: Precision Energy Services, Inc. Project Development Division CROOKED CREEK Page 14 of 16 JDE PRECISION ENERGY SERVICES INC. Discussion The estimation of the capital cost is presented on the attached spreadsheet. The capital cost includes 2 fuel tanks with 25,000 gallons each storage capacity, which is sufficient for about 80 hours. Additional fuel storage for annual requirements is being evaluated by others. The feasibility analyses for 10 and 15 year debt financing periods show expenses and revenue flow during years | through 3 followed by years 11 and 12, and 16 and 17, respectively; the last two columns include data for the years when the operating cost is not burdened by the cost of borrowing money and principal repayment. They show the financials after the loan had been paid off. In the years 4 through 10, of the 10-year financing case and 4 through 15 of the 15 year financing case, the financials are exactly the same as in the second and third years. For the first year we assumed plant availability to be 85%, which accounts for first year operational challenges: running-in, debugging, operator training and similar. In the evaluation with 20 year financing, all columns except the first are similar. Instead of calculating the rate of return on the investment (IRR), we have made an assumption that the plant owner/operator should make a 20% profit before taxes. Based on this, the minimum required sale price for electric power has been calculated. Another assumption is inclusion of the sale of energy for local heating at cost of fuel and 25% margin only. The resulting price of 1 MWe is $112.00 (Solar), $151.90 (Alstom) and $97.00 (GE) in the years when the debt financing is being paid off in the 10 year financing options and $102.50, $141.40 and $88.90, respectively, in the following years. The respective prices for the 15 year financing option are: $109.70 (Solar), $149.60 (Alstom) and $95.00 (GE), respectively in the years with debt repayment and $102.50, $141.40 and $88.90, respectively, in the following years. For the 20 year financing option, the respective prices are: $107.50 (Solar), $148.55 (Alstom) and $94.11 (GE). If the revenue from (and expense on additional fuel for) local heating is not taken into account, the price of 1 MWe would increase on average by 8%. The feasibility evaluation includes also, for comparison, a simplified feasibility analysis of a diesel engine- based generation plant with 10 MWe net output. For simplicity, the capital cost of the diesel engine based generation plant was assumed to be 50% of the cogeneration plant. The comparison shows a clear advantage of the cogeneration plant based on an efficient turbine, such as the GE system; a difference of $25 per MWe in the first 10 and 15 years and $30 in the remaining years; a 13% to 16% cost advantage. The impact of the capital cost on the required price is minimal. First, the change of the capital cost changes the required price ($/MW-hr) only in the first 10 years (during the period of repaying the loan). Afterwards the required price is not affected. Reduction of the capital cost by $1.5 million (17%) results in a change of the required price of $7.00. The greatest impact on the price per MWe has the cost of fuel, which is proportional to the power plant output and the efficiency of the system. The GE system running at its full capacity shows the highest efficiency of fuel utilization, which results in the lowest cost per MW-hr. CROOKED CREEK Page 15 of 16 PRECISION ENERGY SERVICES INC. Please note: all turbine performance data are based on the ambient air temperature of 59°F (15°C, per ISO). With lower air inlet temperature, the turbine output increases and its heat rate decreases. For instance: at 32°F (0°C) the heat rate of the turbine decreases by 3.1%, which can be easily translated into equivalent fuel savings. To increase the turbine efficiency and lower fuel consumption, inlet air fogging systems are being installed on turbines working in hotter climates. The injected water lowers the inlet air temperature and increases the volume of flue gases expanding in the turbine. Inlet air fogging for the system at Crooked Creek will most likely not be needed; the system will be taking advantage of the natural low temperature of the combustion air. As a result, most of the time of operation, the turbine will show better performance than that based on 59°F inlet temperature, as presented herein. As shown in Table 4, the fuel cost is very high, $10.30 per million Btu. CROOKED CREEK Page 16 of 16 1 |Fuel data, #2 Distillate oil, net HV 14 Btu/gal 128,869 1.2 |Density Ib/gal 7.22 Solar Alstom GE 2 |Required electric output, net kw 20,000 2.1 |Parasitic power - turbine (fuel pump, ...) kW 27 NA, as'd 50) 2.2 |Parasitic power - steam system kW 283 2.3 |Required electric output, gross kW 20,310 20,333) 20, 3 |CT turbine output (all outputs at 59°F and sea level) kW 13,613 11,465} 14,51 3.1 |Turbine heat rate Btu/kW-hr 10,100 10,407) 8, 3.2 |Heat input Btu/hr 137,494,000 119,316,000 123,113, 3.3 |Fuel oil input Ib/hr 7,701 6,804) 6,71 3.4 ‘gph 1,067 942] 937 3.5 |Combustion air supply Ib/hr 383,347 310,536 379, [_ 3.6 |Turbine output converted to thermal units Btu/hr 46,449,000 39,119,000) 49,518, 3.7 |Heat content in combustion gases Btu/hr 91,045,000 80,197,000 73,595,000 3.8 |Heat losses in system (convection, radiant) Btu/hr 2,345,800 2,066,300 1,896, 3.9 |Heat loss in FG exhaust Btu/hr 16,293,000 12,845,000) 14,493, 3.10 |Heat available for recovery Btu/hr 72,406,200 65,285,700 57,205,800 4 |Heat recovery steam generator (HRSG) PBO PBO PBO 4.1 |Products of combustion (exhaust, flue gas) Ib/hr 391,048 317,600) 385, 4.2 |Turbine exhaust temperature ie 950 1,003) 4.3 |HRSG system exhaust temperature (GE = output of HW heat exchanger) ne 265 259) 4.4 |Heat losses with flue gas at flue gas temperature Btu/hr 16,293,000 12,845,000 14,493,000 4.5 |Heat available for steam generation Btu/hr 72,406,200 65,285,700 57,205,800 4.6 |Superheated steam generation Ib/hr 61,482 53,554) 57,141 4.7 |Superheated steam properties 700°F, 600# | 754°F,620# | 756°F, 637# 5 |Additional firing 5.1 |DH + DA steam flow lb/hr 19,388 22,293) 20, 5.2 |Power generation with DH and DA steam kW 1,053 1,210 1,110 __5.3 |Power generation in condensing cycle kW 4,303 3,196 3,758 _5.4 |Power generation with condensing & extraction sieam kw 5,356 4,406 4, 5.5 | Total power generation possible without co-firing kW 18,969 15,871 19,381 5.6 |Power generation shortage kW 1,341 4,462 5.7 |Equivalent amount of superheated steam required b/hr 19,524 65,393 14,016 5.8 |Equivalent NET thermal input required in additional firing Btu/hr 25,205,119 84,682,839 18,150,774 5.9 [Equivalent GROSS thermal input required in additional firing Btu/hr 31,102,178 103,480,791 22,331,850 5.10 |Equivalent fuel input for duct burning Ib/hr 1,742 5,796 1,251 5.11 | gaV/hr 241 803) 17: 5.12 |Total fuel input — gaV/hr 1,308 1,745, 41 a {Total fuel demand per day |gal/day 31,397 41,882 26,643 [Total fuel demand for 9 months bbl 201,836 269,244 171,278 6 |Energy balance and efficiencies b 6.1 |District heating energy (includes 95% efficiency)(included in balance) Btw/hr 10,000,000 | 10,000,000 10,000, 6.2 |Converted to equivalent power units kW-hr 2,930 2,930 2,9: 6.3 |Total equivalent power |kW-hr/hr 23,240 23,263 23,273 6.4 |Heat rate | on electric power generation Btu/kW-hr 8,300 10,960 7,150 6.5 |Heat rate li on equivalent power Btu/kW-hr 7,250 9,580 6,250 6.6 |Heat rate II! on electric power generation in CT Btu/kW-hr 10,100 10,410 8,480 6.7 |Plant efficiency | on electric power 47.1% 45.4% 53.7%! 6.8 |Plant efficiency |! on equivalent power 47.0% 35.6% 54.6%: | 7 |Capital cost $ 12,826,773 12,704,703 10,910,133 CC 20 Feasibility! EngSum 07/06/2002 Unit cost per installed electric power $/ kW 632 Unit cost per equivalent power $/ kW eq. 552 546 Heat rate | on electric power generation = total heat input (line 3.2 + 5.9) / power output (line 2.3) Heat rate Il on eg a heat input (line 3.2 + 5.9) / equivalent power output (line Heat rate II! on electric power generation in CT = heat input in CT (line 3.2) / power output (line 2.3) , . = electric power output without co-firing (line 5.5) x 3412 Btu/kWh CT Plant efficiency | on electric power / heat input (line 3.2) = total electric power output without co-firing (line 6.3) x 3412 Btu/kWh / total heat input (line 3.2 + 5.9) Total plant efficiency Il on equivalent power CC 20 Feasibility! EngSum 07/06/2002 CROOKED CREEK, ALASKA, 20 MW COGENERATION PLANT FINANCIAL SUMMARY CC 20 Feasibility! SumALS ALSTOM-BASED PRICING Including local heating system _ J Capital cost 12,704,703 |Financed 75% at 6.25% interest rate IAIN 10 year financing 15 year financing 20 year financing IIIS Il i With P+I payments | W/O P+l payments | With P+l payments | W/O P+l payments | With P+l payments Operating cost, average, first year NI 20,860,896 20,860,896 20,860,896 20,860,896 20,860,896 P+| payments 1,310,064 997,172 847,679 Total expenses i i Tm 22,170,960 20,860,896 21,858,068 20,860,896 21,708,576 Required revenue over expenses | 20% 4,434,192 4,172,179 4,371,614 4,172,179 4,341,715 Revenue from sale of heat at cost of fuel + 25% 25% 1,325,657 ___1,325,657| 1,325,657] 1,325,657 1,325,657 Total required revenue _ 25,279,495 —=s-.23,707,419| —-24,904,025 23,707,419| 24,724,634 Power generated for sale _ 166,440 166,440 166,440 166,440 166,440 Required power sale price 151.88 142.44 149.63 142.44 148.55 Without local heating system Capitalcost 12,488,703 |Financed 75% at 6.25% interest rate 10 year financing 15 year financing 20 year financing IES ____| __| With P+! payments | W/O P+I payments | With P+! payments | W/O P+l payments | With P+! payments Operating cost, average, first year NI 20,860,896 20,860,896 20,860,896 20,860,896 20,860,896 P+I payments iia 1,287,727 980,219 833,267 Total expenses il 22,148,623 20,860,896 21,841,115 20,860,896 21,694,164 Required revenue over expenses 20% 4,429,725 4,172,179 4,368,223 4,172,179 4,338,833 Revenue from sale of heat at cost of fuel + 25% 25% 0 0 0 0 0 Total required revenue _ 26,578,348 25,033,076 26,209,338 25,033,076 26,032,997 Power generated for sale ll 166,440 166,440 166,440 166,440 166,440 Required power sale price 159.69 150.40 157.47 150.40 156.41 Comparable power price with diesel generation 109.82 103.13 108.23 07/06/2002 CROOKED CREEK, ALASKA, 20 MW COGENERATION PLANT FINANCIAL SUMMARY GENERAL ELECTRIC BASED PRICING Including local heating system | as Capitalcost esse! 10,910,133 |Financed 75% at 6.25% interest rate ee ee |= 10 year financing 15 year financing 20 year financing eee ee Sees _| With P+l payments | W/O P+I payments | With P+! payments | W/O P+l payments | With P+ payments Operating cost, average, firstyearNI = 13,429,860 13,429,860 13,429,860 13,429,860 13,429,860 P+! payments 1,125,013 856,361 727,943 Totalexpenses 14,554,874 13,429,860 14,286,221 13,429,860 14,157,803 Required revenue over expenses 20% 2,910,975 oy 2,685,972 1 2,857,244 u 2,685,972 : 2,831,561 Revenue from sale of heat at cost of fuel + 25% | 25% 1,325,657 1,325,657 1,325,657 1,325,657 1,325,657 Total required revenue a= ay 16,140,191 14,790,175 15,817,809 14,790,175 15,663,707 Power generated forsale 166,440 166,440 166,440 166,440 166,440 Required power sale price = 96.97 88.86 95.04 88.86 94.11 Without local heating system ni Capital cost ____ 10,694,133 |Financed 75% at 6.25% interest rate imaial ttt ee = 10 year financing 15 year financing 20 year financing With P+I payments | W/O P+l payments | With P+I payments | W/O P+ payments | With P+! payments Operating cost, average, first year NI 13,429,860 13,429,860 13,429,860 13,429,860 13,429,860 P+! payments 1,102,686 839,366 713,531 Total expenses 14,532,547 13,429,860 14,269,226 13,429,860 14,143,391 Required revenue over expenses 20% 2,906,509 2,685,972 2,853,845 2,685,972 2,828,678 Revenue from sale of heat at cost of fuel + 25% 25% 0 0 0 0 0 Total required revenue 17,439,056 16,115,832 17,123,071 16,115,832 16,972,069 Power generated for sale | ss 166,440 | ____ 166,440 _ 166,440 ___ 166,440 ___ 166,440 Required power sale price 104.78 96.83 102.88 96.83 101.97 Comparable er price with diesel generation 109.82 103.13 107.46 CC 20 Feasibility! SumGE 07/06/2002 CROOKED CREEK 20 MW COGENERATION PLANT FINANCIAL SUMMARY SOLAR TURBINE BASED PRICING Capital cost 12,826,773 |Financed 75% at 6.25% interest rate 10 year financing _ 15 year financing 20 year financing _With P+! payments | W/O P+! payments | With P+! payments | W/O P+l payments | With P+! payments Operating cost, average, first year NI ay "48,317,939 15,317,939 —15,317,939| 15,317,939 ——_‘15,317,939 P+l payments 1,322,575 1,006,745 855,817 Total expenses ne 16,640,514 15,317,939 16,324,684 15,317,939 16,173,756 Required revenue over expenses 20% 3,328,103 3,063,588 3,264,937 3,063,588 3,234,751 aes pl ace Revenue from sale of heat at cost of fuel +25% | 25% 1,325,657 1,325,657 1,325,657 1,325,657 1,325,657 Total required revenue 18,642,959 17,055,870 18,263,963 17,055,870 18,082,850 Power generated for sale 166,440 166,440 166,440 166,440 166,440 Required power sale price : 112.01 102.47 109.73 102.47 108.64 + Without local heating system LLL | TL TOE it Capital cost 12,610,773 |Financed 75% at 6.25% interest rate 10 year financing 15 year financing 20 year financing i With P+I payments | W/O P+! payments | With P+! payments | W/O P+l payments | With P+! payments Operating cost, average, first year NI 15,317,939 15,317,939 15,317,939 15,317,939 15,317,939 P+! payments 1,300,314 989,800 841,412 Total expenses 16,618,253 15,317,939 16,307,739 15,317,939 16,159,351 Required revenue over expenses 20% 3,323,651 3,063,588 3,261,548 3,063,588 3,231,870 Revenue from sale of heat at cost of fuel + 25% = | + 25% 0 O| 0 0 0 eee eee ee eee pa Total required revenue iit 19,941,903 18,381,527 19,569,286 18,381,527 ~ 19,391,221 Power generated for sale 166,440 166,440 166,440 166,440 166,440 Required power sale price 119.81 110.44 117.58 110.44 116.51 109.82 103.13 108.23 103.13 107.46 er price with diesel generation Comparable CC 20 Feasibility1, SumSOL 07/06/2002 MYTH E Talis TITAN 130 Te an Gas Turbine Generator Set Industrial/Utility Grade Features + Industrial Gas Turbine Package + Factory Tested + Onskid Microprocessor-Based + Compact, Integrated Package * Dry, Low Emission (SoLoNO,™) Controls with Auto Sync Capability Providing Ease of Installation Combustion Available + Multiple Fuel Capability Standard Package Configurations Gas Turbine Package + Fuel Systems + Titan™ 130 Industrial, Single-Shaft * Steel Base Frame with Drip Pans — Liquid * Axial Compressor + Direct-Drive AC Start System — Dual (Gas/Liquid) — 14 Stages + Natural Gas Fuel System — Alternate Fuels (such as naphtha, - Variable Geometry * Control System Propane, low Btu gas) — Vertically Split Case - Microprocessor-Based PLC * Lube Oil System — Compression Ratio: 16:1 - Gas Turbine and Generator Control —- Water/Oil Lube Oil Cooler — Speed: 11,200 rpm — Vibration and Temperature Monitoring - Electrostatic Demister + Annular Combustion Chamber = Auto Synchronizing — Duplex Lube Oil Filters — Conventional or Lean-Premixed, + Integrated Lube Oil System * Control System Dry, Low Emission (SoLoNO,) - Turbine-Driven Lube Pump — Remote Display/Contro! Terminal — 21 Fuel Injectors (Conventional) — Pre/Post Lube Pump — Heat Recovery Application Interface — 14 Fuel Injectors (SoLoNO,) — Backup Lube Pump — Serial Link Supervisory Interface + Proximity Probe Vibration Transducers — Air/Oil Cooler — KW Control * Turbine - Integral Lube Oil Tank - KVAR/Power Factor Control — 3 Stage, Axial Flow — Lube Oil Tank Heater - Turbine Performance Map — Speed: 11,200 rpm — Lube Oil Fitter — Historical Displays Main Reduction Drive * Documentation — Printer/Logger * Epicyclic — Drawings ~ Predictive Emissions Monitoring = 1500 or 1800 rpm (50 or 60 Hz) — Quality Control Data Book ~ Field Programming Terminal - Acceleration Vibration Transducer — Inspection and Test Plan * Accessory Equipment Generator ~ Test Reports - ene oor cuneas ie * + Continuous Duty Rating = Operation and Maintenance Manuats ~ is Onliner saat ran + Salient Pole, 3 Phase, 6 Wire, * Factory Testing of Turbine and Package | — Package Lifting Kit Wye Connected, Synchronous with Brushless Exciter Optional Equipment/ : Wreninerrroct cout ee re * Open Drip-Proof Construction Services . ard Etat oyeore aie eee . Sleeve Bearings + NEC Electrical System — Inlet and Exhaust Silencers ; Vetochy Vibration Transducers : * Generator Options: — Self-Cleaning or Prefilter/Barrier oa ~ TEWAC; Standby Duy Rating ali + NEMA Class F Insulation with F Rise Sh eenaare Nokes: = inlet Evaporemve!Cocer 11,000 V (50 Hz); — Inlet Chiller Coils 12,470 or 13,800 V (60 Hz) — Ancillary Support Frame AEE a oe SR ST SS I AT TE C.3. Budget Cost Estimates, Power Plant Fuel Tank Farms at Bethel, Crooked Creek Mine Site 12 Architecture Engineering Surveying Project Management 139 East 51st Avenue Anchorage, AK 99503 Voice (907) 273-1830 Fax (907) 273-1831 P.O. Box 955 Barrow, AK 99723 Voice (907) 852-8212 Fax (907) 852-8213 LCOMF Incorporated { A subsidiary of Ukpeagvik Inupiat Corporation May 10, 2002 Mr. Frank Bettine, P.E., Esq. 1120 E. Huffman Road #343 Anchorage, AK 99515 Re: Budget Cost Estimates Power Plant Fuel Tank Farms Donlin Creek Gold Mine Development Dear Mr. Bettine: LCMEF is pleased to provide budget cost estimates for the design and construction of three Power Plant bulk fuel facility alternatives related to the Donlin Creek Gold Mine development. We understand that you are working for Calista Corporation to identify development costs for three Power Plant alternatives to provide service to the Donlin Creek Gold Mine. As part of this effort, LCMF has been contracted to provide budget design and construction cost estimates for bulk fuel storage and distribution systems for each alternative. The Donlin Creek Gold Mine is located approximately 15 miles to the north of the village of Crooked Creek which is located on the north shore of the Kuskokwim River. Currently, the U.S. Bureau of Indian Affairs (BIA) is planning to construct a road between the a barge landing area, located roughly one mile down-river from the community of Crooked Creek, to the Donlin Creek Gold Mine area. Initially three routes were proposed, however, we understand that the choice has been reduced to two alternatives, both of which are more, or less, straight lines between the two areas. The three Power Plant alternatives, and the related Bulk Fuel Systems, are as follows: 1. Crooked Creek Power Plant and Bulk Fuel System. This alternative is based on construction of a new Power Plant and a new 6 million gallon bulk fuel tank farm near the community of Crooked Creek. 2. Donlin Creek Gold Mine Power Plant and Bulk Fuel System. This alternative is based on construction of a new Power Plant, a new 8 million gallon tank farm at the Power Plant, a new 500,000 gallon tank farm near Crooked Creek to receive fuel from barges and a pipeline to transfer fuel between the two tank farms. Frank Bettine, P.E., Esq. May 10, 2002 Page 2 3. Bethel Coal Fired Power Plant and Back-up Bulk Fuel Tank Farm. This alternative is based on construction of a new coal fired Power Plant with a new 4 million gallon tank farm for back-up fuel storage. BUDGET COST ESTIMATE ASSUMPTIONS The budget cost estimates are based on the requested tank farm storage capacity for each alternative, the stated general assumptions and site specific assumptions. It is understood that no specific sites have been identified for the power plants and tank farms, therefore, no site investigations have been conducted nor have any site specific designs been developed. The estimates do not include property acquisition or leases. Each tank farm alternative has been evaluated based on the selection of a gently sloping site of less than 6% slope. The tank farms are to be constructed using locally mined fill material, gravel or sand, with an imported gravel surface course to provide a suitable driving surface. Each Power Plant tank farm is to be located adjacent to the Power Plant with access provided under the Power Plant construction costs. The tank farm secondary containment system are to use gravel dikes with a continuous low temperature membrane liner (such as Cooley L1023DEP) and a gravel surface course material cover. The tops of the dikes are to be six feet above the interior grade of the tank farm with 4 feet wide tops. Intermediate dikes of at least 18 inches in height are required between the tanks due to the capacities of the individual tanks. Fuel transfer systems to the Power Plant are to be part of the Power Plant construction cost. Each option includes a single pipeline from a marine header to a tank farm sized for a barge off-loading rate of 750 gpm using barge supplied pumps. A bulk storage tank’s usable capacity is calculated at 90% of the tank shell volume. Typically, the top 5% of the tank capacity is not used to allow for thermal expansion and seismic sloshing, and the bottom 5% is not accessible using the standard fuel draw system. Therefore, the tank shell volumes total more than the required even million gallon capacities, which identify the tank farm’s usable capacity. The fuel systems are to be designed and constructed to accommodate the use of No. 2 Diesel, which requires the use of internal heating coils and tank insulation to maintain minimum fuel temperatures during the winter in order to prevent waxing. Waste heat from the Power Plant is to be used to heat the fuel during the winter. This heat exchange system is to be constructed as part of the Power Plant construction. Frank Bettine, P.E., Esq. May 10, 2002 Page 3 Although the tank insulation was initially identified as blown-on, we recommend that a removable insulation system be used, similar to that used on water tanks. A removable system will allow for future external tank inspections as required by the State of Alaska’s Oil Discharge Prevention and Contingency Plans. The insulation system is assumed to be 4-inch thick, with a removable metal cover. The tanks are to be coated under the insulation to prevent corrosion problems. Each tank is also to have an integral spiral stair. No dispensing or truck filling facilities are included at the facilities. In addition to the general requirements stated above, the bulk fuel facilities are to be designed and constructed in accordance with the following regulations and codes: State of Alaska Fire and Life Safety Regulations (13 AAC 50) 2000 International Fire Code (as adopted by 13 AAC 50) 2000 International Building Code (as adopted by 13 AAC 50) State of Alaska Oil and Hazardous Substances Pollution Control Regulations (18 AAC 75) — C-Plan Regulations EPA Oil Pollution Prevention Regulations (40 CFR Part 112) e U.S. Coast Guard Facilities Transferring Oil or Hazardous Material in Bulk Regulations (33 CFR Part 154) Construction costs are estimated based on competitively bid provects. Specific assumptions for each alternative are stated in the descriptions listed below. Crooked Creek Power Plant Bulk Fuel System Specific Assumptions. For the purposes of this cost estimate, the new Crooked Creek Power Plant bulk tank farm is to have a usable storage capacity of 6 million gallons. The tank farm is assumed to be located on the high level ground above the barge landing as shown on the attached Conceptual drawings. This location appears to be well above the flood plain and the site is relatively flat. The Power Plant and tank farm are to be accessed from the BIA road, which is assumed to be constructed prior to the start of the tank farm construction. Gravel fill material is assumed to be mined from an established borrow source located along the BIA road, within three to five miles from the tank farm site. The soil conditions at the site are assumed to be unfrozen with only two feet of overburden that has to be removed before placing local gravel fill material. Fuel is to be delivered to the tank farm through a 6-inch diameter welded steel pipeline, which runs approximately 2,600 feet from a barge landing at the end of the BIA road to the tank farm. Frank Bettine, P.E., Esq. May 10, 2002 Page 4 Donlin Creek Gold Mine Power Plant Bulk Fuel System Specific Assumptions. As shown on the attached Conceptual drawings, the fuel system for the Donlin Creek Gold Mine Power Plant will have a usable storage capacity of 8 million gallons. The Power Plant tank farm is assumed to be located near Omega Gulch with a new pipeline running from a barge off-loading tank farm near Crooked Creek. The Barge off-loading tank farm is assumed to be located on the same site as the Crooked Creek Power Plant tank farm, using the same barge off-loading pipeline. The tank farms are assumed to be located on the level ground as shown on the attached Conceptual drawings. The tank farms are to be accessed from the BIA road, which is assumed to be constructed prior to the start of the tank farm construction. Gravel fill material is assumed to be mined from an established borrow source located along the BIA road, within 3 to 5 miles from the tank farm site. The soil conditions at both sites are assumed to be unfrozen, with only two feet of overburden that has to be removed before placing local gravel fill material. According to Crowley Marine Services, the largest fuel barge that can be used to deliver fuel to Crooked Creek has a capacity of roughly 200,000 gallons. It may be possible to bring a tandem barge tow to the site, which would result in a delivery of 400,000 gallons. Based on this, the Barge Off-Loading tank farm is sized at 500,000 gallons with the intent that the fuel will be pumped to the Power Plant tank farm in less than two days (48 hrs). This timeline requires that fuel be transferred at a rate of approximately 140 gpm. The resulting transfer time to move 8 million gallons of fuel to the Donlin Creek Gold Mine Power Plant is around 40 days. Using a flow rate of 140 gpm through a pipeline with a length of nearly 15 miles (longer road route) creates a significant amount of friction head loss while the elevation head is nearly identical between the two tank farms. As a result of the head loss, we recommend that the pipeline be constructed using at least a 6-inch diameter pipe. The use of HDPE (plastic) pipe was initially identified, and the use of coiled metal tubing was also discussed. Considering the cost of HDPE pipe, the pressure reductions required for hydrocarbon use, and potential permitting problems associated with the use of a plastic pipe, this alternative does not appear feasible. The use of coiled metal tubing may be viable, however, 6-inch coiled tubing is not a standard size and it is unknown if it would be more economical than standard pipe with welded joints. Though originally identified as a pipeline to be laid on top of the ground, we have included the use of pipeline supports to protect the costly investment. It is assumed that the pipeline does not cross state or federal lands and it does not require review and approval by the Joint Pipeline Safety Office. If either of these assumptions are incorrect, a significant cost may be imposed by additional regulatory fees and design changes. It is possible that the Joint Pipeline Safety Office would require the pipeline to be buried for its entire length, which would raise the construction cost by several million dollars and increase permitting costs by around $200,000. Frank Bettine, P.E., Esq. May 10, 2002 Page 5 The transfer pump has been tentatively sized to be a 20-hp vane pump. Given the length of the pipeline, and that it is only used seasonally, the pipeline should be designed to be pig-able so that fuel can be removed from the line when not in use. Bethel Coal Fired Power Plant Back-up Bulk Fuel Tank Farm Specific Assumptions. The new Bethel Power Plant Back-up bulk tank farm is to have a usable storage capacity of 4 million gallons. The location of the future Power Plant is unknown, therefore, the tank farm is assumed to be located within % mile of the Kuskokwim River on an unfrozen site. The soils on the site are assumed to require the removal of two feet of overburden. The tank farm will be constructed using local sand fill, capped with a gravel surface course. Fuel is to be delivered to the tank farm through a 6-inch diameter welded steel pipeline, which runs approximately 2,600 feet from a barge landing on the shore of the Kuskokwim River. BUDGET COST ESTIMATES Using the estimate assumptions listed above, competitive bidding and historic construction costs for rural bulk fuel upgrade projects, the Budget Cost Estimates for these alternative Power Plant Bulk Fuel Systems are as follows: Crooked Creek Power Plant Bulk Fuel System Budget Cost Est.: $7.31 million (Includes $6.66 million for construction, $250,000 for Design, $300,000 for Construction Management and $100,000 for permitting) Donlin Creek Gold Mine Power Plant Bulk Fuel System Budget Cost Est.: $15.30 million (Includes $14.55 million for construction, $300,000 for Design, $350,000 for Construction Management and $150,000 for permitting) Bethel Coal Fired Power Plant Back-up Bulk Fuel System Budget Cost Est.: $5.30 million (Includes $4.7 million for construction, $250,000 for Design, $250,000 for Construction Management and $100,000 for permitting) Frank Bettine, P.E., Esq. May 10, 2002 Page 6 SCHEDULE Construction is anticipated to require two summer seasons for all options, with design and permitting requiring one to two years. If this project was to start early in the summer of 2002, with the preferred alternative already selected, we would anticipate completion of the design during late spring of 2003, too late for bidding and procurement in 2003. The bidding would occur during the summer of 2003 with construction starting in the spring of 2004. The project would most likely be completed in the fall of 2005, hopefully in time to receive fuel for the winter of 2005/2006. We hope that these budget cost estimates are suitable for your use. Please realize that they are very preliminary with several key assumptions that may drastically impact the estimated costs. We would appreciate the opportunity to continue working on this project as it progresses. In the meantime, please feel free to contact me at (907) 273- 1851 if you have any questions or comments. WileyMW. Wilhelm, P.E. Engfeering Manager WWW:www:02-011 Sincerely. Attachments: Conceptual Drawings (sheets 1 — 6) Crooked Creek Power Plant 6,000,000 Gallon Tank Farm Budget Cost Estimate Spreadsheet Donlin Creek Gold Mine Power Plant Tank Farm and Barge Off- Loading System Bethel Coal Fired Power Plant 4,000,000 Gallon Back-Up Tank Farm AUTOCAD DRAWING NAME: 011-6MVM.DWG PLOTTING DATE: 04/10/02 (16:27) } PROPOSED 4 ROAD ‘907 907, 273-1830 852-8212 % “ 2 \ +1320 (1/4 MILE) ij 7a SCALE IN FEET S a ROOKED CREEK POWER PLANT CONCEPTU AL 6,000,000 GALLON TANK FARM LOCATION CROOKED CREEK, ALASKA DRAWN BY: CR DATE: 4/10/02 SCALE: AS SHOWN | CHECKED BY: Www SHEET: W.O. No: 1 02-011 PLOTTING DATE: 05/10/02 (17:06) AUTOCAD DRAWING NAME: 011-SP.DWG i FUTURE _\ 5: 1,340,000 GALLON | (TYP) TANK | N \._ INTERMEDIATE, / DIKE ms a =— STAIRS (TYP) 1,340,000 GALLON 1,340,000 GALLON TANK TANK 1,340,000 GALLON TANK 1,340,000 GALLON 1,340,000 GALLON TANK TANK FROM MARINE HEADER TANK FARM - PLAN VIEW SCALE: 1" = 60° 1,340,000 GALLON TANK (75.6'x40') 1,340,000 GALLON 1,340,000 GALLON TANK TANK (75.6'x40') (75.6'x40') as 10’ VZN 251 or 6. fo TANK FARM - SECTION VIEW NTS LCMF Incorporated A subsidiary of Ukpeagvik Imupiat Corporation Anchorage, Alasko 907) 273-1830 Borrow, Alasko 907) 852-8212 ASSUMED CROOKED CREEK POWER PLANT CONCEPTUAL 6,000,000 GALLON TANK FARM LAYOUT CROOKED CREEK, ALASKA DATE: 3/22/02 DRAWN BY: CR SHEET: 2 SCALE: 1” = 60’ | CHECKED BY: WWW W.O. No: 02-011 AUTOCAD DRAWING NAME; 011-8MVM.DWG PLOTTING DATE: 05/10/02 (16:55) = pH A subsidiary of Ukpeagvik Imupiat Corporation Barrow, Alaska 907) 852-8212 Anchorage, Alasko (302 273-1830 DATE: DONLIN CREEK GOLD MINE POWER PLANT CONCEPTUAL 8,000,000 GALLON TANK FARM LOCATION CROOKED CREEK, ALASKA 4/10/02 DRAWN BY: CR SHEET: S \/ 3 < } es Ff Ue es pas “dd gs AEN BS f ENS | ak t \ H J ) ) SCALE: AS SHOWN | CHECKED BY: Www W.O. No: 02-011 PLOTTING DATE: 04/10/02 (16:54) AUTOCAD DRAWING NAME: 011-SP.0WG FUTURE 1,780,000 GALLON TANK INTERMEDIATE = DIKE r STAIRS (TYP) 1,780,000 1,780,000 GALLON GALLON TANK TANK 1,780,000 GALLON 1,780,000 1,780,000 FROM MARINE HEADER TANK FARM - PLAN VIEW SCALE: 1" = 60 1,780,000 GALLON TANK (87'0x40') 1h 1,780,000 1,780,000 GALLON GALLON TANK TANK . (87'0X40') (87'0X40') © AA me 10’—~+ 1 L : » 1 6% ASSUMED TANK FARM - SECTION VIEW LCMF Incorporated A subsidiary of Ukpeagvik Ifiupiat Corporation Anchorage, Alaska {3033 273-1830 Barrow, Alaska 907) 852-8212 DONLIN CREEK GOLD MINE POWER PLANT CONCEPTUAL 8,000,000 GALLON TANK FARM LAYOUT CROOKED CREEK, ALASKA 3/22/02 DRAWN BY: CR SHEET: 4 SCALE: 1” 60° CHECKED BY: Www W.O. No: 02-011 PLOTTING DATE: 05/10/02 (17:17) AUTOCAD DRAWING NAME: 011~-SP.DWG 250,000 250,000 GALLON TANK FARM - SECTION VIEW CROOKED CREEK CONCEPTUAL BARGE OFF-LOADING TANK FARM LAYOUT CROOKED CREEK, ALASKA 852-8212 Y |DATE: 4/10/02 | DRAWN BY: CR SCALE: 1” = 60° | CHECKED BY: WWW Anchorage, Alasko 907 Borrow, Alaska 907 PLOTTING DATE: 04/10/02 (16:51) AUTOCAD DRAWING NAME: 011-—SP.DWG i FUTURE i | 4,470,000 GALLON 1,470,000 GALLON \ TANK ! TANK INTERMEDIATE DIKE (2% 6) 1,470,000 GALLON FROM MARINE HEADER 1 \ TANK FARM - PLAN VIEW 6 SCALE: 1" = 60° 1,470,000 GALLON 1,470,000 GALLON TANK TANK (79.4'0X40') (79.4'9X40') © “ y , (TYP) — 6% ASSUMED 2 TANK FARM - SECTION VIEW NTS BETHEL POWER PLANT CONCEPTUAL LOMF incorporated BACK-UP 4,000,000 GALLON TANK FARM LAYOUT A subsidiary of Ukpeagvik Ifiupiat Corporation CROOKED CREEK, ALASKA Anchorage, Alasko 907) 273-1830 y Borrow, Alaska {3073 852-8212 DZ DATE: 3/22/02 DRAWN BY: CR SHEET: 6 SCALE: 17 60’ CHECKED BY: Www W.O. No: 02-011 BUDGET COST ESTIMATE Crooked Creek Power Plant 6,000,000 Gallon Tank Farm PROJECT: Crooked Creek Power Plant Tank Farm BY: WWW PROJECT No.: 02-011 FILE NAME: Crooked Cr 6m Tank Farm LEVEL: Budget Budget Cost Est.xls DATE: 5/10/02 . REFERENCE DRAWING(S): Conceptual Drawings BASIS: Competitive Bid FREIGHT RATE: $0.50/lb OTHER OR MATL | MAN COST LABOR | EQUIP RENT _|FREIGHT TOTAL Mobilization/Demobilization .........:+sssssssssssssssssseesseeeseecsseessecssesssesseesnecsuecsnessnessnecseseueesueeseeanecseeseesneesnecseeeees 1 Mob/DeMob 1 SUM 100,000 100,000 100,000 ESE WOGKS cosa aaesavswescnaseerascancsroscanosssen sees uawes ED ToNenis Sans sSesb 40s tSTs Os oNSaSNUISAN be 0ae5s ASUSESAISAAD Ra seesecesoes ce sossoceneapecese 2 2'Overburden Removal 7,400 CY 20 148,000 148,000 3 Gravel Fill 7,859 CY 50 392,972 392,972 4 Tank Farm Primary Liner 88,101 SF 4.00 352,404 44,051 396,455 5 Gravel Surface Course 8" 2,087 CY 120 250,444 250,444 TaMks ooscccesesccsssssseceeccsssssseseccccssssssssssessceeseseeceessssnunsseeecessssunsssessesssnnmsseeesesssnnmssseseenunseeeessnnneeeeeeeesesesen 6 75.6' Dia Foundations 219 CY 1,000 219,039 59,140 278,179 7 1.34 Million Gal Tank (erected) 5 EA 376,227 1,881,134 566,570 2,447,704 8 Tank Insulation 69,945 SF 9.60 671,472 69,945 741,417 9 Tank Coating 69,945 SF 4.00 279,780 2,798 282,578 10 Tank Appurtenances 5 Ls 20,000 100,000 6,250 106,250 Barge Loading/Off-loading Pipelines ..........sssssssssssssscecssseeeeessssssusseecensnnunetseeeeeenssneseeecesnuneesesentneessesssnnnseeseed 11 Coated 6" Sch 80 Pipe 2,600 LF 65 169,000 37,141 206,141 12 Pipe Supports 130 EA 300 39,000 13,000 52,000 13 6" Gate Valve 2 EA 950 1,900 250 2,150 14 6" Check Valve 2 EA 500 1,000 100 1,100 15 Marine Header Containment 1 Ls 7,500 7,500 1,000 8,500 16 Marine Header Assmbly 4 EA 2,500 10,000 1,400 11,400 Tank Hari Pipelines) .........s.«00ciseersannsa0 see sseeawe¥siows sion te yeyeyige sees sau te Yer or Vow gn TeesN saree I654ss Vonmayeey swenusss st saesees uaeeT ERS 17 Coated 6" Sch 40 Pipe 300 LF 60 18,000 4,286 22,286 18 6" Plug Valve 6 EA 2,500 15,000 750 15,750 19 6" Ball Valve 5 EA 750 3,750 625 4,375 20 Pipe Supports 30 EA 300 9,000 3,000 12,000 21 Pig Catcher 1 EA 7,000 7,000 2,500 9,500 Page | of 2 BUDGET COST ESTIMATE Crooked Creek Power Plant 6,000,000 Gallon Tank Farm Security Fencing ......:sssssssssssccssssssssesssssssssccesssssnnnsseeeeesssssunsunnssssssescesesssssusesecsssssiveeeescesssnueeeeeceeceeecee 22 Chain Link Fence 1,200 LF 15) 18,000 9,000 27,000 23 Vehicle Gate 1 EA 4,000 4,000 250 4,250 MOC NOR ac peesasnasqece se tSS0d SEIS SAWRSISSTARRSSSESTENS SEDSESESSSWG SASSI SGITS nocirnsdoais osu sn oesioctowosees sc Joists Sus swtsesN eUNSNESSSIRSTeRsTETSEEH 27,500: 24 Lighting 1 SUM — 25,000___ 25,000 2,500 27,500 Construction Sub-Total: 5,547,952 Contingency @ 20% ___ 1,109,590 ee Construction Total: 6,657,542 Page 2 of 2 BUDGET COST ESTIMATE Donlin Creek Gold Mine Power Plant Tank Farm and Barge Off-Loading System PROJECT: Donlin Creek Power Plant Tank Farm BY: PROJECT No.: 02-011 FILE NAME: LEVEL: Budget DATE: 5/10/02 or REFERENCE DRAWING(S): Conceptual Drawings BASIS: Competitive Bid FREIGHT RATE: $0.50/lb MATERIAL UNIT MATL | MAN COST LABOR ITEM QTY _|UNITS|COST TOTAL | DAYS Www Donlin Cr 8m Tank Farm Budget Cost Est.xls OTHER OR EQUIP RENT_|FREIGHT TOTAL Mobilization/Demobilization! .... 2... --<0--.s0-- sess seus uss uous sasgaesscusssssasaasanssecesssecsssessts seseeaes 1 Mob/DeMob 1 SUM 100,000 100,000 DONLIN CREEK MINE POWER PLANT TANK FARM Earthworks)~ Mine) Tank: Fann 3o.0 0 -sones soycus sp s39sbswose sree aes enw se eecsaee cease uni snaeaananrnaccon sercvnerscce te 2 2' Overburden Removal 8593 CY 20 171,852 3 Gravel Fill 9,340 CY 50 466,983 4 Tank Farm Primary Liner 112,575 SF 4.00 450,300 5 Gravel Surface Course 8" 2,680 CY 120 321,573 Danks Mime Tanks Fare osc. goo nse ee seaones esse sasees sonesaesessoub ss ao ai See cesecasessncsswccrsosupessasesseess 6 87' Dia Foundations 253 | (CY 1,000 253,073 7 1.78 Million Gal Tank (erected) 5 EA 464,680 2,323,401 8 Tank Insulation 84,387 SF 9.60 810,116 9 Tank Coating 84,387 SF 4.00 337,548 10 Tank Appurtenances 5 | ES: 25,000 125,000 Mine Tank Harmt Pipelines 1.0.1.0. sosoves a peesvens spree vasespooasdetesscees sect -oessneersnc-nnwsonnavaenconsivenns 11 Coated 6" Sch 40 Pipe 400 LF 35 —- 14,000 12 6" Plug Valve 6 EA 2,500 15,000 13. 6" Ball Valve 5 EA 750 3,750 14 Pipe Supports 40 EA 300 =: 12,000 15 Pig Catcher 1 EA 7,000 7,000 Security Rencmg carson ni mse ame eeten sate tom or meeeemmran'aivols even ese us soneaeaes ua sede aug sanaae Saat isle ORNe daate oe oa team 16 Chain Link Fence 1,460 LF 15 21,900 17 Vehicle Gate 1 EA 4,000 4,000 Electrical 18 Lighting 1 SUM — 25,000 =. 25,000 Page | of 3 Pats 171,852 466,983 56,288 506,588 321,573 mageeansuseebessesegceeeseat 4,688,919 68,330 321,402 677,439 3,000,840 84,387 894,503 S15) 340,924 6,250 131,250 Slat etatll alta 5,714 19,714 750 15,750 625 4,375 4,000 16,000 2,500 9,500 SE eats 10,950 32,850 250 4,250 2,500 27,500 BUDGET COST ESTIMATE Donlin Creek Gold Mine Power Plant Tank Farm and Barge Off-Loading System MATERIAL UNIT MATL | MAN COST LABOR COST TOTAL | DAYS CROOKED CREEK - DONLIN CREEK PIPELINE 515,225 3,231,225 388,000 1,164,000 1,000 8,600 RAP OLING vs oc vos cs sea cc saces us Soca swiaa Oa 595 1655 9s SSSI 59508 TANT Suwa gwen aE =OE~=oa oor Nad@ a= Ses sean tanowsacen==oasa0=0cs0se cose ancepassqece-oueaa a 19 Coated 6" Sch 40 Buried Pipe 77,600 LF 35 2,716,000 20 Pipe Supports 3,880 EA 200 776,000 21 6" Gate Valve 8 EA 950 7,600 22 6" Check Valve 8 EA 500 4,000 400 4,400 23 Pumphouse 1 Ls 75,000 75,000 7,500 82,500 24 6" Sch 40 Pipe 120. LF 60 7,200 1,714 8,914 25 6" Plug Valve 3 EA 3,500 10,500 375 10,875 26 20 hp Pump 1 EA 20,000 20,000 500 20,500 27 Misc Accessories 1 Ls 10,000 10,000 500 10,500 a 28 Power/Controls 1 SUM 20,000 20,000 2,500 22,500 CROOKED CREEK BARGE OFF-LOADING PIPELINE Earthworks - Barge Off-Loading Tank Farm ........ccsssssssssssssecesssssssesssssssssseseeseccesssssnseesesssssusssecsesssssseseeeceessssses 29 2' Overburden Removal 2,074 CY 20 = 41,481 41,481 30 Gravel Fill 4,161 CY 50 208,039 208,039 31 Tank Farm Primary Liner 23,125 SF 4.00 92,500 11,563 104,063 32 Gravel Surface Course 8" 526 CY 120 63,114 63,114 Tanksi= (Barge Off-Loading /T arile Param tasovacacsxa sow es vac su.vsasassccsssaso = =a seta yr reears avec gees Sooo perso 33 42' Dia Foundations 49 CY 1,000 48,869 13,195 62,064 34 250,000 Gal Tank (erected) 2 EA 120,896 241,791 98,613 340,404 35 Tank Coating 9,104 SF 4.00 36,417 364 36,782 36 Tank Appurtenances 2 Ls 25,000 50,000 2,500 52,500 Barge Off-Loading Tank Farm Pipelines .... 224,788] 37 Coated 6" Sch 40 Pipe 2,600 LF 35. 91,000 17,263 108,263 38 6" Gate Valve 2 EA 950 1,900 250 2,150 39 6" Ball Valve 1 EA 750 750 125 875 40 Pipe Supports 260 EA 300 78,000 26,000 104,000 41 Pig Catcher 1 EA 7,000 7,000 2,500 9,500 Security Fencing 5 5 .vsevereeey uses qs eyues ngseees ss0ssn sues gee eessasessssoaeses0ss Oss Sassen aNESSCNIN User oenrmectaecesesaseevensveiroses~weasons 42 Chain Link Fence 760 LF 15 11,400 5,700 17,100 43 Vehicle Gate 1 EA 4,000 4,000 250 4,250 Page 2 of 3 BUDGET COST ESTIMATE Donlin Creek Gold Mine Power Plant Tank Farm and Barge Off-Loading System Construction Sub-Total: 12,120,953 Contingency @ 20% 2,424,191 Construction Total: 14,545,144 Page 3 of 3 BUDGET COST ESTIMATE Bethel Coal Fired Power Plant 4,000,000 Gallon Back-Up Tank Farm PROJECT: Bethel Power Plant Back-up Tank Farm BY: WWW PROJECT No.: 02-011 FILE NAME: Bethel Power Plant 4m Tank Farm LEVEL: Budget Budget Cost Est.xls DATE: 5/10/02 a REFERENCE DRAWING(S): Conceptual Drawings BASIS: Competitive Bid FREIGHT RATE: $0.35/Ib MATERIAL OTHER OR UNIT MATL | MAN COST LABOR | EQUIP QTY _|UNITS|COST TOTAL | DAYS RENT_|FREIGHT TOTAL Mobilization/Demobilization ................:-:ssssssessssssssssssssnnnssiistiisstssnnsessnntssssnnanstseesecessnssntnnnmnnseeseeeeseeeeee 1 Mob/DeMob 1 SUM 50,000 50,000 50,000 rr Sh osscccannannzat aaa oy svocsv¥v es e705 00 00255 ¥aeausantiadisvesvncsvsysvseceraiienvvigaadivtvoervercroamastismeaeet veapnemsoaeeiee 2 2' Overburden Removal 7,348 CY 20 146,963 146,963 3 Sand Fill 1,737 ‘CY 50 386,844 386,844 4 Tank Farm Primary Liner 87,000 SF 4.00 348,000 30,450 378,450 5 Gravel Surface Course 8" 2,062 CY 120 247,396 247,396 Tanks orcsvsetenstvieieiteisininnnistniisiieniniinmnnnmeiiie 6 79.4' Dia Foundations 139 CY 750 103,934 26,191 130,126 7 1.47 Million Gal Tank (erected) 3 EA 404,788 1,214,363 252,995 1,467,358 8 Tank Insulation 44,787 SF 9.60 429,959 62,702 492,661 9 Tank Coating 44,787 SF 4.00 179,150 1,254 180,404 10 Tank Appurtenances 3 LS 20,000 60,000 2,625 62,625 Barge Loading/Off-loading Pipelines scecacceqceccance roeeasoecesern seco: etacsteccacteensssscooeacedosoesvacsece0ssoceesssuesacenesesssoseedesuat 11 Coated 6" Sch 80 Pipe 2,600 LF 65 169,000 25,999 194,999 12 Pipe Supports 130 EA 300 39,000 9,100 48,100 13 6" Gate Valve 2 EA 950 1,900 175 2,075 14 6" Check Valve 2 EA 500 1,000 70 1,070 15 Marine Header Containment 1 LS 7,500 7,500 1,000 8,500 16 Marine Header Assmbly 4 EA 2,500 10,000 1,400 11,400 Tank: arm PIpelines) os. <ccacow sense sa vevensunsnasosnencoaecacusessnveesnacaaacesuesss<csctcssuoateareusesccdsccnsrerencsosecsseasteanwsncescssscoos 17 Coated 6" Sch 40 Pipe 300 LF 60 18,000 3,000 21,000 18 6" Plug Valve 6 EA 2,500 15,000 525 15,525 19 6" Ball Valve 5 EA 750 3,750 438 4,188 20 Pipe Supports 30 EA 300 9,000 2,100 11,100 21 Pig Catcher 1 EA 7,000 7,000 2,500 9,500 Page 1 of 2 BUDGET COST ESTIMATE Bethel Coal Fired Power Plant 4,000,000 Gallon Back-Up Tank Farm TOTAL Security FenChng scons Poses ssecsccase¥Fcexsscccwserescistsisstslssctsscnvsesccogmutoccosonssscleconsssoacagusssscercnsgdisonsesacconestii fontactee 22 Chain Link Fence 1,340 LF 15 20,100 7,035 27,135 23 Vehicle Gate 1 EA 4,000 4,000 175 4,175 Blectrical s secaccesssnagees ase chntnatis asdsiomedbcccasasccainndapsdacosasereesseve se ssascavesle tis lvassucuessesusssassscosssresuseosesccnsenacorecassss 27,500 24 Lighting 1 SUM — 25,000___ 25,000 2,500 27,500 Construction Sub-Total: 3,929,092 Contingency @ 20% 785,818 Construction Total: 4,714,911 Page 2 of 2