Electric Service Options for Kirkwood

1
Electric Service Options for Kirkwood

• Review Power Engineers Cost Estimate
• Update Assessment of Power Supply Options

KMPUD, 18 September 2009
2
BackgroundMuch work has been done, much is
underway.

• Diesel-fired internal combustion (IC)
  generation was installed in the Kirkwood valley
  during 1972.
• Sierra Pacific Power Company 1997 evaluated
  several transmission line routes.
• Henwood 1999 assessed various power supply
  options, including interconnection.
• BCo 2006 evaluated various power supply, also
  including interconnection.
• Discussions with PGE regarding interconnection
  began during 2007 and continue, but slowly.
• KMPUD efforts thru mid 2009
• Acquisition of MU is substantially negotiated.
  Closing planned during 2010.
• Resource Concepts, Inc. has field biology
  assessments of a transmission line route
  underway.
• Power Engineers completed a design and capital
  cost estimate.
• PGE is considering interconnection, overbuild,
  and route options.
• USFS and CalTrans are informed and involved in
  environmental and routing issues.
• REAC is working as a vehicle for community
  involvement.

3
1.0 Review Power Engineers estimate.

• Power Engineers (PE and PEs report is dated 1
  September 2009) prepared a design and cost
  estimate for a transmission line from Salt Spring
  to Kirkwood.
• 115/230 to 35 kV Salt Spring Substation, 27.3
  mile transmission line, 35 to 12 kV Kirkwood
  substation.
• 13.5 miles direct buried, 5.5 miles under Highway
  88, 5.2 miles under other roads, and 3.1 miles
  overhead.
• 35 kV, 10 MW, 500 kcmil aluminum XLPE cable in
  single conduit. 2.5 to 3.0 loss.
• Substations account for approximately 25 of
  total cost.
• 24.1 million (MM) including 15 contingency.
• In sum
• BCo reviewed PEs work item by item and from a
  total cost perspective.
• Subject to several issues discussed below, both
  PEs design and cost estimate appear reasonable.
• PEs estimate does exclude some of the total
  costs that consumers will ultimately pay.
• Caution, cost estimates change with design, local
  (labor rates, contractor mark ups, ), and global
  (cable, concrete, ) market conditions.

4
1.1 Item by item, PEs estimate appears
reasonable.

• BCo reviewed PEs design and costs, and then
  BCo discussed several items with PE.
• Design assumes a 5 MW peak transfer. 5 growth
  for 20 years means that peak could approach 10
  MW.
• BCo understands from PE that they will evaluate
  a 10 MW case on request.
• Extra voltage regulators and possibly larger
  cable could be necessary. Peak losses could be
  higher.
• Geotechnical assumptions concerning no-rock and
  rock amounts and costs appear reasonable and are
  supported by data from Henkels McCoy.
• Traffic control and safety costs appear ample at
  150 days.
• Overhead line is a replacement of and overbuild
  of an existing 12 kV line.
• PGE charges are a ball park estimate and may
  be low. PEs budget of 345 K could double to
  700 K.
• BCos findings are that
• Concept-level estimate of incremental 5 MW cost
  could be approximately 1 MM.
• PEs cost assumptions reflect current economic
  conditions. A rough industry rule of thumb is
  that costs are now down approximately 15 from
  summer 2008.

5
1.2 Compared to others, PEs estimate appears
reasonable.

• Total cost compared to other transmission line
  projects
• Mix of overbuild, overhead, underground, and
  terrain features make comparisons difficult.
• 15.6 MM plus 15 contingency is approximately
  660/mile.
• Subject to the qualification above, PEs total
  cost per mile is within the range of costs
  experienced by SPP, Kauai Coop, and Puget Sound
  Energy.
• Previous estimates have been concept level
  without the benefit of detailed route analysis
  and engineering.
• BCo 6/06 Conceptual design, 35.4 MM total
  project including 23 contingency. Note that a
  15 saving off this estimate is 30.1 MM, very
  close to the comparable PE figure.
• PGE 2/08 Conceptual design, 53.0 MM including
  unspecified contingency and 100 new back up.
• BCo/PGE 5/08 Trim of PGE estimate by BCo,
  44 MM including 21 contingency.
• KMPUD 3/16/09 Total costs of 35, 45, and 55
  MM used in sensitivity analysis. No break down.

6
1.3 PEs estimate does exclude some costs.
7
2.0 Update Assessment of Power Supply Options

• KMPUD requested a comparison of three broad power
  supply options.
• Modern ICs
• Micro Turbines
• Interconnection to PGE, including PEs design
  and cost results.
• In addition, BCo added a concept-level analysis
  of renewable supplements to key firm supplies.
• In sum, this update confirms previous results.
• Previous evaluations include Henwood 1999 and
  BCo 2006.
• Micro Turbines are more costly than Modern ICs.
• Modern ICs are more costly than Interconnection
  assuming either of moderate load growth or
  increases in diesel fuel costs. Load growth and
  diesel costs are materially uncertain, and
  Interconnection provides other potential benefits.

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2.1 Background on power supply and cost

• For various reasons, Mountain Utilities rates
  have been high and volatile. Recent retail rates
  have been between approximately 0.35/kWh and
  over 0.60/kWh.
• Electric power requirements
• Installed Capacity, gross 6.47 MW 5.34 (MU
  2009) 1.13 (KMPUD 2009).
• Peak Load, gross 3.55 MW 3.30 (BCo 2006,
  update on request) 0.25 (KMPUD 2009).
• Annual Energy, gross 8,656 MWh 7,957 (MU/CPUC
  avg 05-08) 710 (KMPUD avg 05-08)
• Future load depends on uncertain weather, growth,
  conservation, resort operations, and costs.
• Energy costs have been volatile
• Diesel 1.41/gal to 3.57/gal during last year
  and current cost is approx 2.25/gal (KMPUD
  2009).
• Propane 1.50/gal to 2.25/gal during last year
  and current cost is approx 1.60/gal (KMPUD
  2009).
• PGE system power cost 0.06/kWh to 0.08/kWh (PE
  2009 0.060/kWh, PGE 2008 0.077/kWh).
• KMPUD expects to finance capital costs by issuing
  tax-exempt, long-term bonds.

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2.2.1 Install modern internal combustion
generation.

• Install a set of modern diesel-fired IC engines,
  add capacity to match growth as needed.
• Performance, costs and schedule
• 0.075 gal/kWh in service (Caterpillar 830, BCo
  2006).
• Capital cost approx 725/kW (CHP Assn 2009, CEC
  2007, BCo 2006).
• Non-fuel operating cost approx 25/kWyr plus
  15/MWh (CHP Assn 2009, CEC 2007, BCo 2006).
• Diesel costs are volatile.
• Schedule would involve few permitting,
  procurement and construction risks.
• Environmental considerations
• Particulate, CO2, CO, NOx, and SOx emissions.
• Noise during normal operations.
• No access to out-of-valley renewable energy.
• Diesel-based energy for recharge of plug-in
  electric vehicles.

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2.2.2 Install micro turbine generation.

• Install a set of micro turbines, add capacity to
  match growth as needed.
• Performance, costs and schedule
• 11,800 Btu/kWh LHV (Capstone C65 spec). HHV and
  7,800 de-rate to approx 18,000 Btu/kWh.
• Capital cost approx 1,500/kW (CHP Assn 2009, CEC
  2007, BCo 2006).
• Non-fuel operating cost approx 30/kWyr plus
  10/MWh (CHP Assn 2009, CEC 2007, BCo 2006).
• Both diesel and propane costs are volatile.
• Schedule would involve few permitting,
  procurement and construction risks.
• Environmental considerations
• CO2, CO, NOx, and SOx emissions.
• Noise during normal operations.
• No access to out-of-valley renewable energy.
• In-valley, fossil-based energy for recharge of
  plug-in electric vehicles.

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2.2.3 Connect to PGE at Salt Spring.

• Salt Springs PGE substation, 27 mile 34 kV
  mostly underground line, Kirkwood substation.
• Performance, costs and schedule
• Capital cost approx 30.1 MM (PE 2009 plus
  concept-level other costs).
• Transmission line operating cost approx 260 K/yr
  (BCo 2006).
• PGE system power cost is less volatile than
  diesel and propane costs.
• Schedule would involve material permitting but
  few procurement and construction risks.
• In-valley back up from several potential sources
  including KMPUDs own capacity.
• Environmental considerations
• No in-valley emissions except, if any, during
  occasional back-up testing and service.
• No noise except for occasional back-up testing
  and service.
• Access to out-of-valley wind, hydro, solar, and
  biomass renewable energy.
• Grid-based energy for recharge of plug-in
  electric vehicles.

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2.2.4 Develop in-valley renewable generation.

• Supplement gird power or in-valley, fossil-based
  generation with renewable energy.
• Renewable sources have been assessed by Henwood,
  BCo, and others. REAC asserts that renewable
  potential is 5 to 20 of Kirkwoods 8,000 MWh
  energy needs (REAC 9/09, pages 2, 3 w/o
  supporting analysis).
• Wind costs over 2,000/kW, typical capacity
  factor is lt 30. KMR-Synergy wind project 20
  turbines, 6 MWh, cost and schedule unknown. No
  wind studies completed.
• Solar photo voltaic costs over 6,000/kW, typical
  capacity factor is lt 15. No insolation studies
  completed.
• Hydroelectric, typical cost over 3,000/kW,
  typical capacity factor is lt 50. Caples Lake
  potential is unknown, no biological or
  hydrological studies completed.
• Schedules would involve material permitting but
  few procurement and construction risks.
• Non-firm energy requires firm back up, it
  displaces back up energy costs but not capital.
• Environmental considerations
• No incremental in-valley emissions.
• Conflict Hydro (land use, aquatic), wind (land
  use, noise, visual, power quality) and solar
  (land use, visual, power quality).
• Very awkward for recharge of plug-in electric
  vehicles.

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2.3 Micro Turbines are more costly than Modern
ICs.

• BCo 2006 found micro turbines uneconomic due
  primarily to their high capital cost and altitude
  de-rate (BCo 2006, pg 22).
• Simple comparison at right shows calculation of
  the present value of total power costs and a 2010
  c/kWh cost of gross generation.
• This update shows that micro turbines remain
  uneconomic. In particular, they have higher
  capital and fuel costs than modern ICs.

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2.4 Modern ICs are more costly than
Interconnection assuming either moderate load
growth or higher diesel costs.

• Interconnection Appears to be least expensive
  alternative in the long run (Henwood 1999, pg
  3).
• While Option 3 (interconnection) depends on
  substantial load growth and involves the high
  capital costs and challenges associated with
  connecting to either PGE or Sierra Pacific
  Power, if a new transmission line can be built,
  it appears to result in the lowest rates over the
  long term (BCo 2006, pg 3).
• Simple comparison at right is consistent with
  previous results.
• More detailed analysis on following pages.

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2.4.1 More detailed Excel model confirms simple
results.

• BCo prepared an Excel cost model, provided to
  KMPUD, for Modern IC and Interconnection power.
• 30 year time horizon. Performance and cost
  assumptions enumerated on previous pages.
• Structured to evaluate uncertainty surrounding
  load growth, energy costs, and cost of capital.
• Load Growth
• Henwood 1999 forecasted increase from actual
  8,400 MWh in 1999 to over 24,000 MWh at build out
  (pg 22).
• BCo 2006 Likins Forecast of doubling from
  8,870 MWh to over 17,700 MWh at build out (pgs
  8, 31, 33).
• 1 (to 10,562 MWh) and 5 (to 22,968 MWh) for 20
  years are evaluated in this update.
• Energy Costs
• BCo 2006 considered a broad range of future
  diesel costs.
• Current and recent high /gal diesel costs are
  evaluated in this update. Both the PE and PGE
  assumptions concerning system power costs are
  also considered.
• KMPUD Cost of Capital
• Muni bond rates are unusually low as of 9/09,
  approximately 3.5 (BA Merrill).
• 5, 6, and 7 are evaluated and reflect both
  higher benchmark rates and a KMPUD spread.

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2.4.2 Pro forma model results show lower costs.

• Summary of Excel model results at right. Cost
  shown is the 2010 c/kWh cost of power at the
  power house (Modern IC) or Kirkwood Substation
  (Regional Grid).
• Retail rates will be higher and reflect
  power-source independent distribution losses and
  overhead costs.
• IC rate will increase with inflation and diesel
  costs, Interconnection rate will increase with
  inflation.

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2.4.3 There is more to consider.

• Modern IC
• Higher diesel costs of 1.00/gal mean rates are
  higher by 8 to 9 c/kWh.
• BCo has employed middle-of-range cost estimates.
  If and once detailed design is completed, costs
  are more likely to be higher than lower.
• GHG compliance requirements, if any, will
  increase costs.
• Financial model results already include the
  benefit of building out only if and as demand
  increases.
• Interconnection
• A capital cost overrun of 5 MM means rates are
  higher by 2 to 3 c/kWh.
• Sales to communities along the route will lower
  the cost to Kirkwood.
• Risk of high long-term inflation favors
  interconnection. Diesel and incremental capacity
  costs will soar.
• Transfer of the line and retail service to PGE
  may be a long-term option.
• Lowest emissions, lowest noise, highest access to
  large-scale renewable energy, and best potential
  power supply for plug-in electric vehicles.