Goldstrike Power Plant Presentation Tuesday June 21, 2005 Papers/Goldstrike Power Plant.pdf ·...

Goldstrike Power Plant PresentationJune 8, 2006

Goldstrike Power Plant PresentationGoldstrike Power Plant PresentationJune 8, 2006June 8, 2006

Western Mining Electrical Association

Western Mining Electrical Association

2

Goldstrike Mines

Western 102 Power Plant

3

Goldstrike Mines Aerial Photo

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

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

11

Historical Electricity Cost per MW hour

$40

$45

$50

$55

$60

$65

$70

$75

1995 1997 1999 2001 2003 2005

13

Margin Pressure – Gold price

40

45

50

55

60

65

70

75

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

$ / M

WH

250

270

290

310

330

350

370

390

410

430

$ / O

Z

$/MWh $/ounce

14

Margin Pressure – electricity cost

40

45

50

55

60

65

70

75

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

$ / M

WH

10

15

20

25

30

35

40

$ / O

Z

$/MWh $/ounce

15

Annual Peak Demand Forecast

PROCESS PROCESS TOTALYEAR SHOVEL H²0 Underground Autoclave Roaster MISC DEM (MW)

2002 2.6 16.7 18.7 47.8 44.7 2.2 132.72003 2.6 15.0 19.6 47.7 47.7 2.2 134.72004 2.6 14.3 19.7 48.3 47.8 2.2 131.72005 2.6 13.6 19.9 48.3 47.8 2.3 134.52006 2.6 13.1 19.6 48.3 47.8 3.8 135.22007 2.6 12.6 19.1 48.3 47.8 3.8 134.22008 2.6 12.2 16.4 48.3 47.8 3.8 131.12009 2.6 11.7 14.8 44.9 47.8 3.8 125.62010 2.6 1.3 13.3 47.8 3.8 68.82011 2.6 1.3 13.3 47.8 3.8 68.82012 1.6 1.0 47.8 2.1 52.52013 1.6 1.0 47.8 2.1 52.52014 0.8 1.0 47.8 2.1 51.72015 1.0 47.8 2.1 50.92016 1.0 47.8 2.1 50.92017 1.0 47.8 2.1 50.92018 0.8 47.8 2.0 50.62019 0.8 2.0 2.8

BARRICK GOLDSTRIKE ANNUAL PEAK DEMAND (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

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. 40-60 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

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

19

Same technology as Barrick’s Plutonic power plant (4 x 18V34SG – 19 MW)Colorado: 20 x 18V34SG – 111 MWWestern 102: 14 x 20V34SG – 115.6 MW (8,700 BTU heat rate)

Wärtsilä – Reciprocating Engines

Wärtsilä dry cooled power plant near Denver

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)

Number of cylinders(6,8,9,12,16,18,20)

Engine TypeSG = spark gasDF = dual fuelGD = gas dieselNothing = LFO, HFO

Engine TypeSG = spark gasDF = dual fuelGD = gas dieselNothing = LFO, HFO

Cylinder Bore(in cms.)

Cylinder Bore(in cms.)

Cylinder configuration

V or L (R)

Cylinder configuration

V or L (R)

20V34SG

21

Generator Set Power Range

Unit Size MW

LIQUID FUEL 2.0-3.5 3.5-5.0 5.0-7.5 7.5-10.010.0-15.0

15.0-20.0

Wärtsilä Vasa 32 LN

Wärtsilä 32

Wärtsilä 46

GASWärtsilä 34 SG

DUAL FUELWärtsilä 32 DF

Wärtsilä 50 DF

16V46

18V46

12V32

6,9R32LN 12V32LN 16V32LN18V32LN

16V32 18V32

12V32

12V, 18V, 20V, 34SG

18V32DF12V50DF

18V50DF

22

The Basics: Two Types of Gas EnginesThe 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

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

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

25

Location physical requirements

• Access to fuel source• Access to transmission lines• Access to water

26

3

3

3

4

4

4

8

8

230+

230+

230+

230+

230+

345

345

345

345

345 kVproposed

Falcon-Gonder

Valmy522 MW

Tracy/Piñon Pine534 MW

ReidGardnerHarryAllen

Mohave

Davis

Clark

FortChurchill226 MW

Gonder

Falcon

CoyoteCreek Humbolt

Valley Rd

Bordertown

Mira LomaSteamboat

Bella Vista

Oxbow/Dixie Valley

Cove

Battle MtLonetree

AustinMachacek

Round Mt.

Anaconda

Millers

Tonopah

Alkali

Goldfield

Sandia

JackassFlats

Pahrump

SilverPeak

MeadHoover

Eldorad

o

Market-place

Tolson

Faulkner

Basic

ArdenDecatur

Westside

PecosNW

WW

McCulloug

h

Sunrise

300 MW

300 MW

HilltopBPA

Legend:

500 kV345 kV230 kVbelow 200kV

500 MW262 MW

Idaho Power Co.Midpoint

17 MW

17 MWControl

100 MW

120 MW

Summit440 MW

440 MW

235 MW

235 MW

PacifCorp

PG&E

LADWPAnaheimBurbankGlendalePasadenaRiverside

Tuscarora Gas CoPaiute PipelineKern River Gas Co

MAX OUT - 235MWMAX IN -440 MW

Nevada Transmission

27

Western 102 Project - Location

28

IPP Plant

Tracy Plant

Western 102 Plant Site

Interstate 80Reno 10 miles

Western 102 Power Plant Project

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 2004

34

Western 102 Power Plant Project

36

The Standard Section

70’ / 21340

20V34SG Section

Exhaust Gas Silencer

LT-/HT- WaterExpansion Vessel

+ 54’- 2” /+ 16500

SCR/OXI-CAT (optional)

Engine Generator Set

Generator Duct(optional)

Charge Air Filter

Ventilation Unit (Aux.area)Cooler Module (optional)

Auxiliary Module

Exhaust Gas Ventilation Unit

Ventilation Unit(Engine hall)

+ 17’- 8” /+ 5300

+ 29’- 7” /+ 9012

+ 35’- 11½” /+ 10960Rupture Disc

+ 23’- 9”+ 7230

37

Design view from above

38

Design side view – pipe module end

39

Design cross-section iso

40

Design cross section

41

Design - pipe module end

42

Design – gas train side iso

43

Design – gas side view

Construction Photos

45

December 2004December 2004

46

January 17, 2005

48

March 16, 2005

49

March 29, 2005

50

April 26, 2005

51

May 16, 2005

52

May 16, 2005

53

June 9, 2005

56

First Unit Installation

57

Inside Engine Hall B

58

August 24, 2005

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 2005

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

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, 2005

64

Historical Goldstrike Electric Power Costs

Cost/MWh % Change1995 $45.841996 $47.50 4.52%1997 $46.40 -2.31%1998 $45.01 -3.01%1999 $44.87 -0.31%2000 $44.04 -1.84%2001 $59.29 34.61%2002 $66.49 12.14%2003 $67.14 0.99%2004 $68.51 2.04%2005 $72.63 5.34%

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%

66

Annual Peak Demand Forecast

PROCESS PROCESS TOTALYEAR SHOVEL H²0 Underground Autoclave Roaster MISC DEM (MW)

2002 2.6 16.7 18.7 47.8 44.7 2.2 132.72003 2.6 15.0 19.6 47.7 47.7 2.2 134.72004 2.6 14.3 19.7 48.3 47.8 2.2 131.72005 2.6 13.6 19.9 48.3 47.8 2.3 134.52006 2.6 13.1 19.6 48.3 47.8 3.8 135.22007 2.6 12.6 19.1 48.3 47.8 3.8 134.22008 2.6 12.2 16.4 48.3 47.8 3.8 131.12009 2.6 11.7 14.8 44.9 47.8 3.8 125.62010 2.6 1.3 13.3 47.8 3.8 68.82011 2.6 1.3 13.3 47.8 3.8 68.82012 1.6 1.0 47.8 2.1 52.52013 1.6 1.0 47.8 2.1 52.52014 0.8 1.0 47.8 2.1 51.72015 1.0 47.8 2.1 50.92016 1.0 47.8 2.1 50.92017 1.0 47.8 2.1 50.92018 0.8 47.8 2.0 50.62019 0.8 2.0 2.8

BARRICK GOLDSTRIKE ANNUAL PEAK DEMAND (MW)

67

Western 102 Looking North

68

Dove Substation and Inside Engine Hall A

69

O&M

• Bid process – PIC selection• Schedule & staffing• Training & plant commissioning• Consumables – natural gas & oil

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)

71

O&M Organization Chart

Barrick Plant ManagerBarrick Plant ManagerAdministration/FinanceFacility ManagerFacility Manager

Operations Supervisor

Operator

Operations Supervisor

Operator

Operator

Operator

Instrumentation Technician

Instrumentation Technician

Mechanical Technician





72

Forecast – Natural Gas Costs

$0

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

$70,000,000

23% 30% 40% 50% 60%Time Plant Opportunistically Idled

Natural Gas Costs at $9, 7, 5/DT

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.

74

Forecasted Resources for Load

6/6/2006 FORECAST NAMTIE / SOURCE1 25 TOTAL

FORECASTED LOAD:6/6/2006 BARRICK POS 10 0 10

PROJECTED GENERATION:6/6/2006 WESTERN 102 NEG -5 0 -5

PROJECTED IMPORTS:6/6/2006 BARRICK M345 NEG -5 0 06/6/2006 BARRICK HILLTOP345 NEG 0 0 06/6/2006 BARRICK GON.IPP NEG 0 0 06/6/2006 BARRICK GON.PAV NEG 0 0 06/6/2006 BARRICK SPPC NEG 0 0 0

TOTAL IMPORTS: -5 0 -5

TOTAL RESOURCES (GEN & IMPORTS): -10 0 -10

NET (LOAD - RESOURCES): 0 0 0(SHOULD NET TO ZERO)

HOURLY PROFILE 01-25

75

Forecast

• Major loads = Roaster, Mill / Autoclave, Underground, Water Management – each area to submit schedule to aggregator – allow for maintenance.

• Imbalance charges • Load following

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

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

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&MOR

– The market proxy, COB minus transmission of $8.56/Mwh and minus losses of 6.46%

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 cost80% of decremental cost

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

81

Historic Imbalance Charges

Cost Pay Cost Pay Cost PayMay-04 70.2 54.2Jun-04 68.3 46.0 75.5 47.4 83.3 42.1Jul-04 71.2 55.2 83.9 51.5Aug-04 67.1 54.1 48.0 43.7Sep-04 60.2 45.4 59.5 43.4Oct-04 64.9 51.0Nov-04 75.7 58.3 93.0 52.8Dec-04 76.9 58.2 89.0 54.8Jan-05 69.7 56.2Feb-05 64.7 53.6Mar-05 75.6 60.7Apr-05 79.9 64.3

Band 1 Band 2 Band 3

Hourly Imbalance Cost/MWh

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

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

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?

85

NotificationSC Initiates Contact

Autoclave Control Room

1 2 3On-Call Autoclave Supervisor

4

Roaster Control Mill Control

5 6

Shift Supervisor

Technicians

Air Liquide

Plant Manager

Electrical Engineering

7 8

Open Pit Manager

Meikle Hoist Room

On-Call General Foreman

SuperintendentShift Supervisor

Air Products

Superintendent

Shift Supervisor

Technicians

Technicians

General or On-Call Manager

Process Manager

Water Mgmt Shift Supervisor

86

Load Reduction

Tier 1 Load Reduction Load Shed (MW) CumulativeGen set - Roaster 0.80 0.80Gen set - Roaster 0.85 1.65Gen set - Autoclave 0.85 2.50Gen set - Autoclave 0.80 3.30Gen set - Mill 1.90 5.20Mill Gyro (48 hour max) 0.56 5.76Mill Jaw 0.22 5.98Roaster Gyro/MP800 (48 hours max) 1.00 6.98Water Management - A 1.60 8.58

Tier 1 Load Shed 8.58

Tier 2 Load ReductionMill 1 6.20 14.78Air Liquide ( 855 tons of GOX/day ) 2.50 17.28


Tier 3 Load ReductionAir Liquide ( 600 tons of GOX/day - notice? ) 3.00 20.28Mill 2 8.00 28.28


Tier 4 Load ReductionRoaster Mill 1 8.50 36.78

87

Load Reduction Continued

Tier 5 Load Reduction Load Shed (MW) CumulativeAutoclaves, Pumphouse, Cooling Tower, Ph. IV Boiler 7.50 44.28

Tier 6 Load ReductionRemaining Mill/Autoclave Loads 5.50 49.78Meikle Mine refridgeration plant 2.80 52.58


Tier 7 Load ReductionRoaster Mill 2 8.50 61.08

Tier 8 Load ReductionRemaining Roaster Mill Loads (fans) 3.00 64.08Roasters and pumping 4.50 68.58


Tier 9 Load ReductionMeikle Mine 8.00 76.58

88

Load Reduction Continued

Tier 10 Load Reduction Load Shed (MW) CumulativeWater Management - B 3.30 79.88Gen set Roaster 0.85 80.73Gen set 'Clave 0.85 81.58Gen set 'Clave 0.85 82.43Air Liquide 2.00 84.43


Tier 11 Load ReductionAir Products 12.00 96.43

Tier 12 Load ReductionAir Liquide 10.00 106.43

Tier 13 Load ReductionBalance of Wells, 602, etc. 7.40 113.83

Tier 14 Load ReductionRodeo 7.00 120.83Electric Shovels 2.50 123.33


Balance of loads - Sierra activated trip signals 12.00 135.33

89

Metering

• SPPCo retrofit to real time hardware

• Data to Western 102 in near real time – Web site updated at ten minute intervals

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, 2005

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

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

Goldstrike Power Plant Presentation Tuesday June 21, 2005 Papers/Goldstrike Power Plant.pdf ·...

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