Goldstrike Power Plant Presentation June 8, Western Mining Electrical Association

Transcription

1 Goldstrike Power Plant Presentation June 8, 2006 Western Mining Electrical Association

2 Goldstrike Mines Western 102 Power Plant 2

3 Goldstrike Mines Aerial Photo 3

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9 Load Summary Roaster facility 46 MW Mill / Autoclave 47 MW Underground 21 MW Water Management 13 MW Electric Shovels 3 MW Miscellaneous 4 MW TOTAL 134 MW 9

10 Utility Billing Elements 19 delivery points at 10 locations aggregated Time of Use rate structure 15-minute Demand periods Energy Power Factor Meter and facilities charges (fixed monthly fees) Barrick negotiated Tier 3 special rates Beginning late 2000, introduced F&PP, CEP, DEAA, UEC, etc. charges 10

11 Historical Electricity Cost per MW hour $75 $70 $65 $60 $55 $50 $45 $

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13 Margin Pressure Gold price $ / MWH $ / OZ $/MWh $/ounce 13

14 Margin Pressure electricity cost $ / MWH $ / OZ $/MWh $/ounce 14

15 Annual Peak Demand Forecast BARRICK GOLDSTRIKE ANNUAL PEAK DEMAND (MW) PROCESS PROCESS TOTAL YEAR SHOVEL H²0 Underground Autoclave Roaster MISC DEM (MW)

16 Project Background Nevada law first allowed exit in December 2001 under AB 661. We needed to reverse price increases and stabilize costs. Remaining with the financially weak utility did not present a viable option. Barrick wanted a power plant that could provide: Priority #1: Predictable, lower cost power Priority #2: Timing that coincides with load profile Priority #3: Reasonable investment return Options considered: Power supply agreements (Idaho, IPP) Purchase an existing plant Carlin-area self-generation alternatives Gas pipeline from Wyoming to California Joint venture (NGC & FPL) Joint Venture expansion of utility-owned generation Self-generation 16

17 Late emerging issues Single Largest Contingency Defined as largest generation loss that could possibly occur. Language interpreted as AB 661 applicant must provide spare capacity if this event transpires so that load is still served.or it goes black. For the recips considered, 8.25 MW vs with LM 6000 turbines 14 gensets vs. 2 combustion turbines plus 1 steam Water Looking into water availability and water rights, it became clear that it would be expensive, if available at all Recips estimated at 200 gallons per week vs. 180 gpm for boiler make-up water and more for evaporative cooling or intake injection 17

18 Technology Choice Drivers Fuel type and source Heat Rate Simple or combined cycle? Engine size and type (turbine vs. reciprocating) Water requirements Lead time permits, engineering, manufacturing Flexibility react to market load following Single Largest Contingency Emissions 18

19 Wärtsilä Reciprocating Engines Same technology as Barrick s Plutonic power plant (4 x 18V34SG 19 MW) Colorado: 20 x 18V34SG 111 MW Western 102: 14 x 20V34SG MW (8,700 BTU heat rate) Wärtsilä dry cooled power plant near Denver 19

20 Wärtsilä Nomenclature Wärtsilä make what are termed medium speed engines Speeds range from 400 rpm to 1,000 rpm Typical Wärtsilä name: Number of cylinders (6,8,9,12,16,18,20) 20V34SG Cylinder configuration V or L (R) Engine Type SG = spark gas DF = dual fuel GD = gas diesel Nothing = LFO, HFO Cylinder Bore (in cms.) 20

21 Generator Set Power Range Unit Size MW LIQUID FUEL Wärtsilä Vasa 32 LN 6,9R32LN 12V32LN 16V32LN 18V32LN Wärtsilä 32 12V32 16V32 18V32 Wärtsilä 46 12V32 16V46 18V46 GAS Wärtsilä 34 SG 12V, 18V, 20V, 34SG DUAL FUEL Wärtsilä 32 DF 18V32DF 12V50DF Wärtsilä 50 DF 18V50DF 21

22 The Basics: Two Types of Gas Engines Spark Ignited (SG) Runs on 100% natural gas, lean burn, spark ignited Dual Fuel (DF) Runs on 99% natural gas + 1% pilot fuel OR 100% liquid fuel oil 22

23 20V34SG 720 RPM Length: 42.3 ft., Width: 10.3 ft., Height 16.0 ft., Weight: 140 tons Output: 8,440 kwe, Heat rate: 8,700 BTU/kWh 23

24 Exit Process File notice of intent to leave; identify resources File for transmission rights System Impact Study May lead to facilities study; estimate for system upgrades Agreements Transmission Service Agreement Network Operating Agreement Large Generator Interconnection Agreement Interconnect Operating Agreement Distribution Only Service Includes real-time metering Scheduling Coordinator Gas & Electricity 24

25 Location physical requirements Access to fuel source Access to transmission lines Access to water 25

26 345 Nevada Transmission 3 BPA Hilltop300 MW 4 Idaho Power Co. Midpoint 262 MW 500 MW 300 MW Valmy 522 MW Coyote Creek Humbolt Lonetree Battle Mt Falcon Cove 100 MW Summit 120 MW PG&E Bordertown 4 3Tracy/Pi ñon Pine 534 MW Valley Rd Bella Vista Mira Loma Steamboat MW Fort Churchill 226 MW Control 17 MW Oxbow/ Dixie Valley 230+ Millers Tonopah Alkali Silver Peak Goldfield 230+ Anaconda Austin Round Mt. Sandia Machacek 345 kv proposed Falcon-Gonder Gonder 230+ PacifCorp 235 MW 440 MW MAX OUT - 235MW MAX IN -440 MW 440 MW 235 MW LADWP Anaheim Burbank Glendale Pasadena Riverside Legend: kv 345 kv 230 kv below 200kV Tuscarora Gas Co Paiute Pipeline Kern River Gas Co Jackass Flats Pahrump Westside Decatur Arden 8 NW Reid Gardner Harry Allen Pecos Faulkner WW Basic Tolson Marketplace McCullough Eldorado Clark Sunrise Hoover Mead Davis Mohave 26

27 Western 102 Project - Location 27

28 Western 102 Power Plant Project IPP Plant Western 102 Plant Site Tracy Plant Interstate 80 Reno 10 miles 28

29 Timeline Deregulation pronounced in 2001 (AB 661) Allows large industrial users or aggregated loads > 5MW to exit bundled service from serving utility AFE submitted to Board June 2004 Permits obtained by September 2004 EPC contract signed October 2004 (after 3 ½ months of negotiations) Ground-breaking November

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34 Western 102 Power Plant Project 34

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36 The Standard Section / V34SG Section Exhaust Gas Ventilation Unit Ventilation Unit (Engine hall) Exhaust Gas Silencer Rupture Disc SCR/OXI-CAT (optional) LT-/HT- Water Expansion Vessel Charge Air Filter ½ / / Generator Duct (optional) / Ventilation Unit (Aux.area) Auxiliary Module Cooler Module (optional) Engine Generator Set 70 /

37 Design view from above 37

38 Design side view pipe module end 38

39 Design cross-section iso 39

40 Design cross section 40

41 Design - pipe module end 41

42 Design gas train side iso 42

43 Design gas side view 43

44 Construction Photos

45 December

46 January 17,

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48 March 16,

49 March 29,

50 April 26,

51 May 16,

52 May 16,

53 June 9,

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56 First Unit Installation 56

57 Inside Engine Hall B 57

58 August 24,

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61 More Project Timelines Schedule October 28, 2005 substantial completion November 1, 2005 ready for commercial production Scheduling Coordinator RFP s solicited with presentations by candidates in December 2004 Selection of Avista Energy February 2005 Signed agreement June 2005 O & M Contractor Began search in February / March 2005 Selection made in May

62 How Things Change BGMI effectively becomes its own utility With electric transmission and gas pipeline capacity BGMI assumes control of energy costs Must now operate a control area responsible for: Forecasting capacity and energy needs Matching load and resources Gas and electricity purchases Scheduling maintenance of major electric components (at the mine site) can offer opportunities for cost savings 62

63 Exit from Utility s Energy Service Background Experienced rising energy cost from utility Two year process Exit under state legislated plan Responsible for providing new energy resources Pay a stipulated exit fee Target date November 1,

64 Historical Goldstrike Electric Power Costs Cost/MWh % Change 1995 $ $ % 1997 $ % 1998 $ % 1999 $ % 2000 $ % 2001 $ % 2002 $ % 2003 $ % 2004 $ % 2005 $ % 64

65 Resources W102 = 115MW Tolling 3 years Import = 50 MW stipulated firm pro rata Midpoint to Humboldt until load declines (then 32%) Non-firm on this and other routes Renewable and conservation requirement 6% of purchased energy, growing to 20% Losses Transmission & Distribution 3.6% 65

66 Annual Peak Demand Forecast BARRICK GOLDSTRIKE ANNUAL PEAK DEMAND (MW) PROCESS PROCESS TOTAL YEAR SHOVEL H²0 Underground Autoclave Roaster MISC DEM (MW)

67 Western 102 Looking North 67

68 Dove Substation and Inside Engine Hall A 68

69 O&M Bid process PIC selection Schedule & staffing Training & plant commissioning Consumables natural gas & oil 69

70 Plant Staffing 1 x Barrick Employee based on site Larry Morasse Goldstrike Power Plant Manager PIC Operations & Maintenance Staffing (14 total) PIC Manager Operators (5) Mechanics (6) E & I Technicians (2) 70

71 O&M Organization Chart Barrick Barrick Plant Plant Manager Manager Facility Facility Manager Manager Administration/Finance Operations Supervisor Operations Supervisor Operator Mechanical Technician Instrumentation Technician Operator Mechanical Technician Instrumentation Technician Operator Mechanical Technician Operator Mechanical Technician Mechanical Technician 71

72 Forecast Natural Gas Costs $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 Natural Gas Costs at $9, 7, 5/DT $0 23% 30% 40% 50% 60% Time Plant Opportunistically Idled 72

73 Scheduling Coordinator Scope of responsibilities 24 x 7 x 365 operation at the Real-time desk Primary interface between BGMI and the utility Optimize resources, buying and selling gas and electricity Schedules Annual by month, monthly by week, week ahead by hour, day ahead by hour before 10:00 a.m. 73

74 Forecasted Resources for Load 6/6/2006 FORECAST NAMTIE / SOURCE HOURLY PROFILE TOTAL FORECASTED LOAD: 6/6/2006 BARRICK POS PROJECTED GENERATION: 6/6/2006 WESTERN 102 NEG PROJECTED IMPORTS: 6/6/2006 BARRICK M345 NEG /6/2006 BARRICK HILLTOP345 NEG /6/2006 BARRICK GON.IPP NEG /6/2006 BARRICK GON.PAV NEG /6/2006 BARRICK SPPC NEG TOTAL IMPORTS: TOTAL RESOURCES (GEN & IMPORTS): NET (LOAD - RESOURCES): (SHOULD NET TO ZERO) 74

75 Forecast Major loads = Roaster, Mill / Autoclave, Underground, Water Management each area to submit schedule to aggregator allow for maintenance. Imbalance charges Load following 75

76 Importance of Forecasting Accuracy Need to plan for electric and fuel requirements Planning maintenance outages for W102 generation Hourly mismatch between load and resources can cost BGMI 76

77 Load Imbalance Energy Imbalance Service is provided when a difference occurs, between the scheduled and the actual delivery of energy, to a load located within a Control Area over a single hour Bandwidth of +/- 1.5% with a minimum of +/- 2.0 MW Negative (energy provided to the mine by Utility) 100% of providers incremental cost Positive (energy provided to Utility by BGMI) 100% of providers decremental cost 77

78 Cost Incremental Cost The highest hourly system incremental generation cost, including average O&M OR The market proxy, California Oregon Border (COB) price plus transmission of $8.56/Mwh plus losses of 6.46% Decremental Cost The highest hourly system incremental cost, excluding average O&M OR The market proxy, COB minus transmission of $8.56/Mwh and minus losses of 6.46% 78

79 Aggregated Imbalance The Utility accounts for all customers taking imbalance service based on an aggregate, (both positive and negative) within a 4 MW bandwidth Example If Barrick is minus 2 and Other is plus 2, they will cancel each other If the aggregate imbalance is greater than 4 MW, the below listed penalties or discounts on energy apply < 5 MW 110% of incremental cost 90% of decremental cost > 5 MW 120% of incremental cost 80% of decremental cost 79

80 Deviations from Schedule During an emergency, the Utility may request an instructed deviation. If Barrick complies by increasing generation or decreasing load, then Sierra would pay 100% of decremental cost The Utility may call on Barrick to balance its schedule if they feel we are intentionally overproducing to force them to purchase energy. If we fail to comply, they will not pay us anything 80

81 Historic Imbalance Charges Hourly Imbalance Cost/MWh Band 1 Band 2 Band 3 Cost Pay Cost Pay Cost Pay May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr

82 Generation Imbalance Western 102 is subject to the same provisions for deviations in schedule vs. actual deliveries For hourly deviations where changes in load are offset by changes in generation, there are no charges 82

83 Load Following Do not know the imbalance charges until the month has passed If we under-generate by 5 Mw (4% of average load) every hour for a peak month, the payment to the Utility could be $250,000 If we over-generate by the same amount, the cost to Barrick may be $75k-$100k in increased cost Western 102 utilizes dynamic load following This software controlled system uses the near real time mine load information to change Western 102 output 83

84 RAS & TRP RAS What is it? When does it apply? Impact to site? TRP What is it? When does it apply? Impact to site? 84

85 Notification SC Initiates Contact 1 2 Autoclave Control Room 3 On-Call Autoclave Supervisor Roaster Control Air Products Superintendent Mill Control Shift Superintendent Supervisor Technicians Shift Supervisor Technicians Air Liquide Plant Manager Water Mgmt Shift Supervisor On-Call General Foreman Electrical Engineering Shift Supervisor Meikle Hoist Room Open Pit Manager Technicians Process Manager General or On-Call Manager 85

86 Load Reduction Tier 1 Load Reduction Load Shed (MW) Cumulative Gen set - Roaster Gen set - Roaster Gen set - Autoclave Gen set - Autoclave Gen set - Mill Mill Gyro (48 hour max) Mill Jaw Roaster Gyro/MP800 (48 hours max) Water Management - A Tier 1 Load Shed 8.58 Tier 2 Load Reduction Mill Air Liquide ( 855 tons of GOX/day ) Tier 2 Load Shed 8.70 Tier 3 Load Reduction Air Liquide ( 600 tons of GOX/day - notice? ) Mill Tier 3 Load Shed Tier 4 Load Reduction Roaster Mill

87 Load Reduction Continued Tier 5 Load Reduction Load Shed (MW) Cumulative Autoclaves, Pumphouse, Cooling Tower, Ph. IV Boiler Tier 6 Load Reduction Remaining Mill/Autoclave Loads Meikle Mine refridgeration plant Tier 6 Load Shed 8.30 Tier 7 Load Reduction Roaster Mill Tier 8 Load Reduction Remaining Roaster Mill Loads (fans) Roasters and pumping Tier 8 Load Shed 7.50 Tier 9 Load Reduction Meikle Mine

88 Load Reduction Continued Tier 10 Load Reduction Load Shed (MW) Cumulative Water Management - B Gen set Roaster Gen set 'Clave Gen set 'Clave Air Liquide Tier 10 Load Shed 7.85 Tier 11 Load Reduction Air Products Tier 12 Load Reduction Air Liquide Tier 13 Load Reduction Balance of Wells, 602, etc Tier 14 Load Reduction Rodeo Electric Shovels Tier 14 Load Shed 9.50 Balance of loads - Sierra activated trip signals

89 Metering SPPCo retrofit to real time hardware Data to Western 102 in near real time Web site updated at ten minute intervals 89

90 Practice Need to appoint representatives & schedule rep training with Avista site visit This should cover process upsets, power outages, communication channels, etc. Schedule July 12,

91 Summary The Western 102 project is on schedule for completion by November 1, 2005 The project in combination with additional purchased resources will offer BGMI better control of energy prices for the future PIC will provide O&M services for Western 102 Staffing is currently underway Avista Energy Services will provide scheduling and optimization services Daily load forecasting is a new responsibility for the mine and we need to appoint representatives to submit the forecast Imbalance charges from Sierra can be significant for mismatches between schedule and actual load Efforts are underway to control imbalance through dynamic load following The Remedial Action Scheme and Transmission Reduction Plan are important to reliable service and mine management must be prepared to respond to emergencies Avista and BGMI must schedule training and practice sessions beginning in July for schedule preparation and emergency response 91

92 This Project Provides a physical hedge that mitigates the impact of rising fuel & energy prices Has a stabilizing effect on energy costs Provides a return on investment while improving cash costs versus the price paid to the Utility Is reliable by virtue of 14 gensets plus 50 MW of firm import capacity Does not guarantee an absolute lowest cost for energy Does not guarantee a fixed cost for energy 92

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