1. Resource cost and Potential

2. Background and Introduction
Potential and costs were all updated in late 2013 by Black & Veatch
Information from internal sources, market data, and other literature (LBNL, DOE, CEC)
When possible, previously-vetted information from other Black & Veatch stakeholder projects was used and updated:
Renewable Energy Transmission Initiative ( )
Western Renewable Energy Zones (2009, )
SB1122 Biomass Feed-in Tariff (2013)
NREL Renewable Electricity Futures (2010)

3. Approach – General Methodology
26 December 2012
Approach – General Methodology
Capital Cost Updates
Costs are “all-in” installed costs and include EPC + owner’s costs (soft costs)
Costs include costs through the interconnection to the T&D system
Costs are for 2013 projects – cost forecast curves developed for all technologies as well
Operation and Maintenance (O&M) Cost Updates
O&M cost estimates include all other annual costs, including land lease, insurance, and property tax (exclusion to be updated)
Resource potential and performance was updated for all technologies compared to the RETI assessment
Major methodology changes made for wind and solar PV
Small-scale bioenergy from SB 1122 analysis
Minor updates to all other resources (Solar Thermal, Geothermal, Biomass)
Full detail for the approach can be see in the PPT, “RPS_CalcV6.0_ResourcePotentialandCost” on the CPUC website
PowerPoint Sample

4. Summary of Changes to Solar PV
Cost updated for systems from 1 to 20+ MW (ac rating)
Fixed Tilt and Single Axis Tracking
Black & Veatch assumes little appreciable economies-of-scale after 20 MW. Therefore a single estimate is provided for systems that size and larger.
Smaller-scale rooftop systems also included (250 kWac)
Higher performance systems assumed
Increased dc to ac ratio, also known as inverter loading ratio (up to 1.4)
Higher ac capacity factors
Capital costs include a $200/kW allowance for interconnection costs (except for rooftop, where interconnection costs are assumed to be minor and included in the system costs)
While overall trend is decreasing solar PV costs, higher performance is achieved by increasing inverter loading ratio which increases capital cost

5. Solar PV Performance Significantly Higher than Previously Estimated (RETI 1B Max CF = 28%, now 35+%)
Fixed Tilt
Tracking
Capacity Factor (ac) 5

6. Solar PV Capital Costs

7. Planned Solar Cost Updates
Costs continue to decline; down roughly 25% since the estimates were performed for v.6.0
Will use market data and Black & Veatch design data to refresh current costs and performance for v.6.1
Modify future cost curves and evaluate as part of sensitivity cases
Source: LBNL

8. Wind Performance
Most high capacity factor sites in California have been developed
Black & Veatch re-assessed wind potential in California applying newer low wind speed turbines as appropriate
Many new areas included, especially northern California
Similar approach as RETI

9. and project size limitations
Results
Apply exclusions
and project size limitations
LCOE state-wind estimates
NCF at identified utility scale project sites 9

10. Northern California Previously Identified CREZ (2008-2010)
Geothermal
Wind
Wind
Wind
Wind

11. Northern California Current Potential Wind Projects
Previously Identified CREZ ( )

12. Capital Cost Assumptions
BASE COSTS:
Steeper terrain makes some areas more expensive to develop. Modifiers based on slope were used to account for terrain:
Direct Costs calculated as:
Base Turbine Costs + (Slope Multiplier)*(BOP/erection + Switchyard)
Owner’s cost was assumed to be 15% of the direct costs
Category
Class I, 80m
Class II, 80m
Class III, 100m
Turbine ($/kW)
950
1,100
1,250
BOP/erection ($/kW)
400
420
475
Switchyard ($/kW)
150
Slope
Multiplier
Less than 4 percent
1.00
Between 4 percent and 8 percent
1.16
Between 8 percent and 16 percent
1.22
Greater than 16 percent
1.55

13. Wind and Other Resource Updates
Wind costs down roughly 5 percent since the v.6.0 estimates were performed
Will use market data and Black & Veatch design data to estimate current costs and performance
Updates to biomass, geothermal, and solar thermal will largely reflect general escalation only
Source: LBNL

14. Cost Sensitivities
Cost inputs can be changed as desired in the calculator to test sensitivities
Version 6.1 of calculator could have the functionality to more easily run alternatives if desired. Options include (1) scenarios, (2) sensitivities, and (3) Monte Carlo.

15. Out of State Resources
Out-of-state resources may be competitive in certain instances
All out-of-state of resource estimates from updated Western Renewable Energy Zones Project (WREZ)
Wind
Solar PV
Solar Thermal
Geothermal
Hydro

16. Out of State Updates
Calculator currently differentiates out of state resources by performance but not cost
Plan to apply new analysis performed by Black & Veatch differentiating the performance, capital cost, O&M cost, and LCOE throughout the US in V6.1
Will not create new zone boundaries

17. Super crez identification

18. Zone Identification
From , Black & Veatch worked with stakeholders to identify Competitive Renewable Energy Zones (CREZ) as part of the Renewable Energy Transmission Initiative (RETI)
These zones were subsequently used in various different processes by various stakeholders
In , Black & Veatch reassessed renewable resources to address significant improvements in technology, particularly with wind and solar PV
Resource availability much more widespread
Many new wind resources in northern California
Updated zone definitions are needed to reflect the updated resource assessment

19. Updated Renewable Resource Assessment
Wind, Biomass, Geothermal, and Solar Thermal Project Locations
Solar PV not shown, but is available across the state (see next slide)
For wind, substantial shift north, into non-CREZ areas

20. Solar PV Resource (Tracking PV)
Widespread and generally good quality throughout California
Most of resource is outside previous CREZ boundaries

21. Principles For Updating Zone Boundaries
New zones based on:  
“Legacy” 2010 CREZ to the extent possible
Locations of ~150 projects which have been “tagged” to zones in the CPUC’s 2012 RPS calculator
Project Development Status Reports
CEC Renewable Energy Action Team
Expanded resource assessment (tried to not split newly identified projects into two zones)
Transmission topology
Geographic constraints
County boundaries

22. Differences From Previous CREZs
Previous CREZ identified the best resources for large scale transmission development considering technical, economic and environmental factors
Very specific boundaries, sometimes capturing specific project boundaries and interconnection lines
Purposefully made as small as possible (“shrink-wrapped”) to minimize perceived environmental footprint
Current zones are intended to capture most of the resources in California regardless of relative economic or environmental considerations
Not for siting or environmental assessment - used for categorization and assigning transmission upgrade cost
More comprehensive coverage - “puzzle pieces”
Boundaries less meaningful
No particular advantage to being in a zone

23. Legacy CREZ (Westlands Area)

24. 2012 Utility Contracts Tagged To CREZ

25. 2012 Utility Contracts Tagged To CREZ

26. New “Super CREZ”

27. New Super CREZ Boundaries
All of these zones correspond with a legacy zone name or a zone in the 2012 RPS calculator (Los Banos, Central Valley North)
No new zones identified by B&V, except Sacramento River Valley
Resources outsides zones summarized by county

28. Super CREZ Environmental Exclusions
Intent of the calculator is to not prejudge permitting or provide opinion on preferred development location
Only removed stakeholder-vetted lands where development is prohibited or practically impossible:
RETI Category 1
WECC EDTF Category 4
Feinstein California Desert Protection Act
Environmental ranking and scoring would be the next step to prioritize particular areas
Future workshops will address incorporation of environmental ranking and consideration of further additional environmental screens
Super CREZ resource potential incorporates environmental exclusions even though the boundaries are not drawn with this intent

29. 2010 Monterey Area CREZ

30. Constraints, Resources and Infrastructure

31. New Monterey Area Renewable Resources

32. Monterey County Super CREZ

33. Super CREZ Transmission
Super CREZ sizing and transmission
Concern that expanded CREZs may in some cases be too inclusive and include areas with differing transmission conditions and costs
Discussed issue with CAISO; follow up on this issue will be addressed in a wider discussion regarding process development for updates to the RPS Calculator
Cost updates
Will be working with CAISO to update both in-state and out-of-state transmission costs

34. Transmission Costs

35. Transmission Cost in RPS Calculator
The availability and cost of transmission are primary components in the calculation used to rank competing resources
They reflect the cost to deliver new renewable generation to California loads
The methodology of identifying available capacity and transmission costs in v.6.0 is generally the same as previous version, additional updates planned
RPS Calculator Valuation Framework +
Levelized Cost of Energy +
Transmission Cost −
Capacity Value −
Energy Value +
Curtailment Cost +
Integration Cost* =
Net Resource Cost

36. RPS Calculator in Transmission Planning
RPS Calculator receives information from and provides information to CAISO transmission planning processes
Transmission projects included in CAISO Transmission Planning Process (TPP) are recovered through the Transmission Access Charge (TAC) levied on all users of the transmission system
TAC costs are passed on to ratepayers
Generation projects accessing transmission lines in the TPP may avoid additional delivery network upgrade (DNU) costs
Since the CAISO TPP is based on the CPUC’s RPS Calculator portfolios, it is critical the overall process shown here works
CAISO GIDAP
Transmission Inputs
Available Capacity [MW]
Delivery Network Upgrade (DNU) Costs
[$/kW-yr]
Iterative - informs next cycle and other processes
RPS Portfolios
CAISO TPP
Commercial Projects [MW]
RPS Calculator
CPUC LTPP
Generic Projects
[MW]

37. Summary of Planned Updates to Transmission Cost
Transmission availability and cost estimates for all transmission upgrades will be updated in v.6.1 of the RPS Calculator to reflect all available CAISO study information
Additional information on data sources provided in this presentation
The CPUC is considering stakeholder process alignment to formalize a process for future transmission cost updates.
Also identified major resource areas for which new transmission cost estimates may be needed (Sacramento River Valley)

38. Methodology Overview Transmission costs split in three categories
Interconnection Cost
Delivery Network Upgrades (minor and major upgrades)
Out-of-state Transmission

39. Interconnection Cost Gen-tie line Substation New switching station
New breaker position at existing station

40. Interconnection Unit Cost Source
interconnection cost estimates based on the CAISO Participating Transmission Owner unit cost estimates.
Costs vary depending on interconnecting utility.

41. Interconnection Cost Estimates
RPS calculator applies IOU unit costs to calculate the total interconnection equipment costs (gen tie, line tap, bay expansion, etc.) for each project
Two substation options based on project location:
Project A is within reasonable gen-tie distance – new breaker position at existing substation
Project B is not within reasonable gen-tie distance, but can connect to the 115 kV line – new switching station
Project A 20 MW
Project B
20 MW
Sub A 115 kV
Sub B 115 kV
115 kV Line

42. Interconnection Cost Updates
Latest available version of unit costs from annual CAISO Stakeholder process will be implemented in Version 6.1 of the RPS Calculator.
Additional environmental cost categories that are not considered could be implemented through the CAISO’s annual process.

43. Delivery Network Upgrade (DNU) Costs
DNU costs consist of minor and major upgrades
Three categories:
Available transmission capacity with no upgrades
Available transmission capacity with minor upgrades
Available transmission capacity with major upgrades
Costs do not reflect any sunk costs (e.g., Tehachapi)

44. Delivery Network Upgrade (DNU) Cost Sources
CAISO provides DNU costs in the RPS Calculator for a subset of Super CREZ based on the following two primary sources:
Participating Transmission Owner cost estimates from Interconnection Studies
Investor Owned Utility estimates for policy driven studies included in Transmission Planning Process (TPP)
CAISO will provide stakeholders references to specific studies used to develop the DNU costs in the calculator
In general, TPP studies are available on the CAISO website and interconnection studies can be accessed through the CAISO Market Participant Portal
For transmission projects for which CAISO does not provide input, generic assumptions are used to calculate the cost of a new “conceptual” transmission project

45. Transmission Capacity (GW)
Round Mountain
Available transmission capacity in 2020 on existing transmission (no additional upgrades)
Sacramento River Valley
(GW)
Solano
3.8 GW
Eldorado
Carrizo
Mountain Pass
Kramer
Tehachapi
Riverside
Imperial

46. Transmission Capacity (GW)
Round Mountain
Available transmission capacity in 2020 on existing transmission (no additional upgrades)
Minor upgrades
Tehachapi: $0.1B
Westlands : $1.5B
Sacramento River Valley
(GW)
Solano
Eldorado
Westlands
Carrizo
Mountain Pass
Kramer
Tehachapi
Riverside
Imperial

47. Transmission Capacity (GW)
Round Mountain
Available transmission capacity in 2020 on existing transmission (no additional upgrades)
Minor upgrades
Tehachapi: $0.1B
Westlands : $1.5B
Major upgrades
Kramer: $0.4B
Imperial: $0.9B
Riverside 1: $1B
Riverside 2: $1.8B
Sacramento River Valley
(GW)
Solano
Eldorado
Westlands
Carrizo
Mountain Pass
Kramer
Tehachapi
Riverside
Imperial

48. Conceptual Transmission Costs
For SuperCREZs where CAISO does not provide information on the cost or availability of new transmission, costs of new high voltage transmission projects are estimated based on unit cost information
Costs for such “conceptual” projects in v.6.0 are taken directly from v.5.0
Based on E3’s transmission costing model developed for the GHG Calculator
Black & Veatch will updated costs for conceptual projects in v.6.1 using the utilities’ PTO unit costs

49. DNU Cost Updates: Key Challenges
Updated resources are assigned to new Super CREZ because many resources are outside of the original CREZ boundaries

50. DNU Cost Updates: Key Challenges
Transmission Infrastructure in Central California
Some new Super CREZ are very large
These Super CREZ face common major transmission constraints
CAISO has not yet developed more granular cost estimates for constraints within these zones
May change as new information is developed

51. Delivery Network Upgrade (DNU) Costs Updates: Key Challenges
CAISO has not studied all areas and so transmission availability and costs for minor and major upgrades in numerous areas have not been established.
Capacity limited to amount in queue
Limited number of minor upgrade solutions
Minor upgrades are typically classified as local network upgrades and are implemented to mitigate local issues on the system
Often accounted for in interconnection studies and costs

52. Out of State Transmission Costs
Largely based on previously vetted initiatives:
RETI 2B (2010)
B&V work for WECC on transmission costs ( )
WREZ Generation and Transmission Cost Model ( )
Given the size and magnitude of new out of state projects being proposed, assumes that no existing transmission is available

53. Out of State Transmission Approach
Out-of-state transmission costs
Delivered to “gateway CREZs” (e.g., Mountain Pass)
Routing from WREZ Generation and Transmission model
Updated cost basis: 500 kV single-circuit ac transmission, 1500 MW capacity, $2.0 million/mile (2015 dollars)
In-state transmission costs:
Added CAISO DNU costs to OOS costs using same approach as California projects
When Energy Only is implemented into the calculator, projects that do not require full deliverability, will not incur DNU costs

54. Out of State Transmission Costs Update
Transmission costs were inflated at 1.5% from 2012 to 2013, and at 2.0% from 2013 to 2014.
Based on inflation values assumed for the 2014 WECC Transmission Cost Calculator update.
Transmission costs were inflated at 2% from 2014 to 2015.
Inflation cost was based on commodity prices, Consumer Price Index, and ENR Construction Cost Index.

55. Out of State Transmission Costs Updates
Original cost basis for OOS lines assumed 500 kV ac lines for all lines
High Voltage Direct Current (HVDC) may be economically feasible for longer distance lines
600 kV HVDC Cost Basis:
+/- 600 kV bipole circuit
3000 MW capacity
$1.6 million / mile
600 kV HVDC converter station: $517 million
DC line losses also likely lower

56. Out of State Transmission Costs Updates
Example
725 Mile, 600 kV HV DC line to bring 3000 MW out of state resource to CA. Assumed HVDC converter station required on each end.
600 kV DC
500 kV Single AC
Base Cost per mile, $/mile
$1,645,000
$1,958,000
Distance, miles
725
Line cost, $
$1,192,965,000
$1,419,430,000
Converter Stations / Substations Cost, $
$1,033,830,000
$195,784,000
Total Cost, $
$2,226,795,000
$1,615,214,000
Capacity, MW
3000
1500
$/kw
$742
$1,077

57. AC vs. DC Transmission Capital Costs
Numerous other factors influence the selection of line type

58. Distributed Generation

59. Presentation Overview
Introduction
Resource Potential Update
DG Costs and Value
Future RPS Calculator Inputs and DG Sizing

60. Role of DG Analysis in the RPS Calculator
DG projects included in the RPS Calculator demonstrate likely offsets in transmission and generation investment required for scenarios of high DG installation
DG has seen near exponential growth and reached over 3,000 MWac
State incentives under CSI and other programs have historically driven DG growth
However, in 2014, the majority of behind the meter PV installations were completed without state incentives
There is non-solar PV DG (e.g. wind and bioenergy) state incentives, such as SB 1122, driving additional development
Growth of Behind the Meter DG in California, [1]
[1] Black & Veatch estimate based on historical state incentive program data and Greentech Media Research reports on installed PV capacity in

61. DG Implementation in the RPS Calculator
B&V High Resolution GIS Analysis
Resource Potential – Parcel Level (MW) +
B&V Capital Cost Estimates
E3/LDPV Cost Estimate
(will be revised by DRP)
B&V Cost Estimate for SCE
DG Capital Cost – Parcel Level ($/kW)
DG Cost/Value – Substation Level ($/kW)
DG Interconnection Cost – Substation Level ($/kW)
RPS Calculator Input (from above sources)
RPS Calculator Input
(15% of peak load, in the future may be revised by DRP)
DG Supply Curve
DG Scenarios in RPS Calculator

62. RPS Calculator and the Distribution Resources Plan (DRP)
RPS Calculator will focus on impacts at the transmission level
Aggregates parcel, feeder and distribution resolution
Impacts of DG between Super CREZ
DRP will focus on impacts at the feeder and distribution substation level
Impacts of DG within a Super CREZ
Resource valuation being examined in the DRP will be applied to the RPS Calculator to extent they are consistent with Calculator functionality
Details of the DRP’s DG valuation are currently undetermined, but inputs will be anticipated in Version 6.1 of the RPS calculator
Much of DRP will be submitted to the Commission July 1, 2015
Prior to release of DRP submittals, information from Black & Veatch updated resource assessment and E3’s Local Distributed PV study will be used in the Calculator

63. Refined Resource Assessment
In September 2013, Black & Veatch completed a “Southern California DG Potential Study” to identify PV potential around key SCE 230 kV substations affected by SONGS retirement
New analysis techniques to identify potential project size and cost of energy
Included residential and commercial/industrial rooftops
First ever assessment of parking lots
Study identified significant PV in urban areas, especially for high concentration DG (HCDG) connected to subtransmission system
20+ MW projects
Expansion of this analysis begun for the entire state; will take into consideration geographic and transmission limits

64. Area Near John Wayne Airport
Technical Potential
Capacity, MWdc
0.25
> 3 64

65. Example Detail (1. 1 MWdc Rooftop, 7 MWdc Parking Lot, Approx
Example Detail (1.1 MWdc Rooftop, 7 MWdc Parking Lot, Approx. $120/MWh)
Technical Potential
Capacity, MWdc
0.25
> 3
The assessment found significantly more potential than previous studies – particularly by including potential for PV development on parking lots 65

66. Resource Potential Comments
Majority of respondents favored updates to the PV resource potential
Past assessments have been limited
Current model is constrained when exploring future policies emphasizing high PV penetration
Helps to inform DRP process
Identify potential for high concentration DG within Local Capacity Requirements (LCR) areas
Improves future siting

67. Updated Resource Assessment Approach
Expanded version of the Southern California assessment
Use previously described approach to quantify PV potential for:
Commercial and industrial (C&I) roofs
Parking lots
Residential parcels (average size assumed by zip code)
Gather parcel data and USGS aerial imagery data for large metro areas in California
Limit to areas within the CAISO (excludes Los Angeles and Sacramento)
Calculator will assume wholesale DG for residential, commercial, and industrial locations
No resource updates planned for wind or bioenergy

68. Updated DG Resource Assessment: Study Area
Utility-scale PV resources located in orange-red areas in map
Urbanized areas shown in black

69. Updated DG Resource Assessment: Study Area
Major metro areas were focused upon to capture the majority of the potential
Captures 11 largest municipalities (~20 million residents) and the majority of the potential in the Bay Area, LA Metro (x-LADWP), and San Diego
For rooftop potential in other areas, the level of granularity was not considered useful at Super CREZ level
All areas also within LCR zones, though not all LCR zones in analysis

70. Study Area – Southern California Example

71. Study Area – Orange County

72. Study Area – Orange County
Previously performed assessment

73. PV Potential will be Plotted Against Interconnection Maps Published by Utilities

74. DG Capital Cost Updates
LCOEs for DG resources are typically higher than utility scale units:
Solar: Based on Black & Veatch large rooftop identification in 2009 and E3 Local Distributed PV study in 2012
Wind : New 2013 assessment; 20 percent adder to large scale costs for dis-economies of scale
Bioenergy: Used SB 1122 cost and resource assumptions
Methodology and assumptions described in “California Renewable Energy Resource Potential and Cost Update” presentation

75. DG Capital Cost Updates
Capital costs for solar DG resources will be updated in a manner similar to utility-scale renewable resources
Solar: ~25% decline in capital cost
Wind: ~5% decline in capital cost
Biomass: increase with general escalation

76. DG Value
Calculator uses same methodology to value large and small-scale resources
Potential direct ratepayer benefits that small-scale projects located near loads may provide:
Reduced system losses
Avoided congestion costs
Avoided need for generation in capacity-constrained areas such as LCR areas
Deferral/avoidance of investments in transmission infrastructure
Deferral/avoidance of investments in distribution infrastructure
Currently:
RPS Calculator does not assign transmission costs to small-scale resources (other than interconnection costs)
RPS Calculator thus calculates trade-off between small-scale and transmission-constrained renewables based solely on avoided transmission costs

77. DG Value Comments
Differing opinions on the value of DG. Majority of the responses indicated that DG value was challenging to quantify, very site specific, and the potential benefits may be captured by utility-scale resource as well depending on the location.
The cost/benefit for DG is under extensive study in the DRP process:
DRP Study Elements
RPS Calculator
Locational Net Benefits
Will use DRP values
Previously based on LDPV study results
Barriers
Will consider adding based on DRP findings
Not presently included in Calculator
Capacity Assessment in Urban Areas
Will use DRP findings when available
Interim approach will assume percent of minimum load at subtransmission substation

78. Interconnection Cost Assumptions
The DRP is expected to provide improved information on the cost to interconnect DG in different IOU service areas
Until results from the DRP are available, simplified approach to interconnection costs based on penetration of substation capacity:
“Low cost” interconnection limit to be 30% of transmission and distribution substation capacity
First 15% of systems can be accommodated by existing distribution system with minor upgrades
Estimated cost $100/kW or less
Second 15% (up to 30%) will require more extensive upgrades similar to those identified in the Navigant study for SCE
Estimated cost $300/kW or less
Individual and aggregated systems above 30% local penetration will require additional upgrades (such as dedicated feeders).
Estimated cost $500/kW or less
PV potential above 100% penetration will be quantified as theoretical, but not technical potential

79. Future RPS Calculator Inputs and Parameters
Input DG supply curve generated from new resource potential site identification and project capital costs
Cost/Benefit Parameters will be defined based on outcome of DRP
Generation carve outs can be applied to account for existing incentive programs (e.g. SB 1122)
Substation load can be adjusted to represent assumptions in “behind the meter” DG installations

80. Creating DG Portfolios
Present approach will be to limit DG output based on percentage of peak load at urban transmission substations
Present assumption is 15% of peak load, but this will be a controllable parameter in the calculator
Estimate the value that a high DG case would need to provide in order to favor DG resources over utility scale projects