Distributed PV is the low cost, high value answer for meeting California’s 33% by 2020 target Feed-In Tariff Workshop, San Francisco Bill Powers, P.E., Powers Engineering July 12, 2010
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In-Basin solar PV feed-in tariff for Los Angeles: composite initial tariff ~$220/MWh source: UCLA & LABC, Bringing Solar Energy to Los Angeles – Assessment of Feed-In Tariff, July 2010, p. 32.
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CEC “levelized cost-of-energy” (LCOE) for new merchant peaker turbines is $800 to $1,000/MWh source: CEC, Comparative Cost of Electric Generation Technologies, January 2010, Table 4 and Table 5. Note – the dates shown in the table, 2009 and 2018, are commercial start dates.
Combustion turbine (MW)
Capacity factor (%)
LCOE 2009 ($/MWh)
LCOE 2018 ($/MWh)
50
5
844
1,009
100
5
795
951
3
CEC LCOE for new merchant combined cycle $186/MWh at 65% capacity factor in 2018 source: CEC, Comparative Costs of California Central Station Electricity Generation , January 2010, Table 1, Table 5, Figure A-8. Note – the dates shown in the table, 2009 and 2018, are commercial start dates.
Combined cycle plant (MW)
Capacity factor (%)
LCOE 2009 ($/MWh)
LCOE 2018 ($/MWh)
500
92
118
161
500
90
119
162
500
75
124
169
500
65
136
186
500
55
149
203
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CEC, DOE: Solar PV cost will drop in half by 2020 sources: 1) CEC, Comparative Costs of California Central Station Electricity Generation , January 2010, Figure 8, 2) DOE, Solar Vision Study – Draft, Chapter 4: Photovoltaics: Technologies, Cost, and Performance, May 28, 2010, Table 4-2, p. 17.
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No operational combined cycle plant could meet “market price referent” (MPR) capacity factor source: CEC, Comparative Costs of California Central Station Electricity Generation , January 2010, Table C-5.
The MPR calculation assumes combined cycle baseload potential capacity factor (CF) of 92% is achieved. This results in least-cost combined cycle power and a nearly unachievable price point for renewable power. In reality, no combined cycle in California actually achieves 92% CF, and only two are at 75% or above. Average in 2008-2009 for combined cycle fleet was 65%. CEC assumes 70-75% combined cycle CF in its January 2010 comparative electricity generation cost analysis. CARB assumes 65% CF in June 2010 draft report on cost to achieve 33% Renewable Electricity Standard by 2020.
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Residential tiered rates: ~20,000 GWh at rates from $0.24/kWh to $0.40/kWh ($240 to $400/MWh) sources: 1) PG&E A. 10-03-014 General Rate Case Phase 2 filing, Chapter 3, 2) CEC 2009 Integrated Energy Policy Report (IEPR), Figure 4, p. 52. Assumption – residential IOU customer consumption is 2/3 of total statewide residential consumption.
California’s investor-owned utilities (IOUs) bill residential customers using tiered rates: Tier 1 and 2 in $0.12 to $0.15/kWh range, Tiers 3, 4, and 5 from $0.24 to $0.40/kWh. In PG&E territory, about a third of residential usage is billed at Tier 3 or above. California IOU residential customers used ~60,000 GWh in 2008. Assuming the PG&E ratio for the other two California IOUs, about 20,000 GWh was billed at Tier 3 or higher rates. 20,000 GWh represents the production of 10,000 to 12,000 MW of distributed PV capacity.
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LCOE for solar PV and solar thermal – RETI Phase 2B Report source: Renewable Energy Transmission Initiative (RETI) Phase 2B Final Report, May 2010, Tables 4-5, 4-7, 4-8.
Technology
Capacity (MW)
Capacity factor (%)
LCOE ($/MWh)
Solar thermal, dry-cooled
200
20-28
195 - 226
Fixed thin-film PV
20
20-27
138 - 206
Tracking polysilicon PV
20
23-31
135 - 214
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RETI - Range of renewable energy LCOE values source: RETI Phase 2B Final Report, May 2010, Figure 4-1. Dark green bars are May 2010 costs. Light green bars are superseded 2008 costs.
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Cost of new transmission – Achilles heel of remote central station generation sources: 1) RPS Calculator, 2) J. Firooz, P.E., CAISO: How its transmission planning process has lost sight of the public’s interest, prepared for UCAN, April 15, 2010.
CPUC calculated $34/MWh transmission adder in June 2009 for remote renewable generation. CPUC assumed renewable generation financed over 20 yr, transmission over 40 yr. Adder is $46/MWh if generation and transmission financed over same 20 yr period (apples-to-apples). CPUC adder assumes total new transmission requirement of $12 billion to reach 33% by 2020. Combined RETI new transmission (> $15 billion) + CAISO reinforcement of existing transmission grid ($12 billion) exceeded $27 billion as of September 2009. Total transmission + upgrades adder: $100/MWh or more? 10
Interest in high distributed PV case source: E3/B&V - ReDEC working group meeting, Summary of PV Potential Assessment in RETI and the 33% Implementation Analysis, December 2009, p. 11.
"If it is conservatively assumed that only 10,000 MW of new high voltage transmission will be built by 2020 to realize the RETI net short target of 68,000 GWh, the estimated cost of this transmission will be in the range of $20 billion in 2008 dollars based on SDG&E’s projections for the Sunrise Powerlink. How much thin-film PV located at IOU substations or at the point-of-use on commercial buildings or parking lots could the IOUs purchase for this same $20 billion? ... This equals an installed thin-film PV capacity of 14,000 to 18,000 MW for a $20 billion investment." Bill Powers, PE, testimony in SDG&E’s Sunrise Powerlink CPCN case 11
Summer peak availability - sun and wind are not the same Resource
Reference
Capacity factor (%)
Tracking PV
CPUC/E3, June 2009
77
Fixed rooftop PV
Itron, Jan 2010 analysis of 2008 CAISO peak hr
59
Fixed rooftop PV
Itron, July 2010 analysis of 2009 CAISO peak hr
59
Onshore wind
CARB/E3 June 2010 33% RES draft report
11
Onshore wind
NERC 2010 study of 20% national RPS
17
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Utilities – wind power must be backed-up by combustion turbines
World without RPS requirements – utilities build combustion turbines to meet rising peak load.
World with RPS requirements – utilities build combustion turbines, and wind turbines, and new transmission to meet rising peak load.
Or central station solar thermal or solar PV, and new transmission.
Or distributed solar PV (ideally with limited 2 to 3 hr energy storage), and no new transmission. 13
How much distributed PV could we tie to grid without substantive substation upgrades? source: CPUC Rulemaking R.08-08-009 – California RPS Program, Administrative Law Judge’s Ruling on Additional Commission Consideration of a Feed-In Tariff, Attachment A - Energy Division FIT Staff Proposal, March 27, 2009.
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About 13,000 MW at IOU distribution substations, ~20,000 MW statewide Note: IOUs supply about 2/3 of electricity in state, public utilities and others supply remaining 1/3.
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The 21st century smart grid, with full bidirectional flow at every substation source: CEC 2007 Integrated Energy Policy Report, December 2009, p. 155.
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Utilities spend ¾ of total budgets on distribution system, but not yet building for 21st century source: CEC 2007 IEPR, December 2009, pp. 155.-156
“Utilities spend approximately three-fourths of their total capital budgets on distribution assets, with about two-thirds spent on upgrades/new infrastructure in most years.”
“Investments will remain for 20 to 30 or more years.”
“Magnitude of these investments suggests need to require utilities, before undertaking investments in non-advanced grid technologies, to demonstrate that alternative investments in advanced grid technologies that will support grid flexibility have been considered, including from a standpoint of cost-effectiveness.” 17
RETI’s “highly technical question” – is not a substantive impediment source: RETI Net Short Update – Discussion Draft, February 22, 2010, p. 7.
Potential for substantial development of distributed PV: “When the advent of lower cost PV projects of 20 MW or smaller and occupying sites of about 100 acres or less, the potential exists for substantial development of distributed solar generation located close to urban loads and connected to the grid at lower voltage substations in the electric distribution system.”
Highly technical question – how much distributed PV without compromising safety and reliability of grid? “The distribution system, however, is designed to enable energy from the high voltage transmission system to reach consumers, not to transmit energy in the opposite direction. The highly technical question of how much distributed generation can be connected without compromising safety and reliability has not been fully investigated and resolved.”
18
DOE on current cost of distributed utility-scale PV source: DOE, Solar Vision Study – Draft, Chapter 4: Photovoltaics: Technologies, Cost, and Performance, May 28, 2010, Figure 4-4, p. 7.
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DOE on current cost of commercial rooftop PV source: DOE, Solar Vision Study – Draft, Chapter 4: Photovoltaics: Technologies, Cost, and Performance, May 28, 2010, Figure 4-4, p. 7.
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B&V/E3: Off-the-mark with PV cost estimates for CPUC LTPP process – inexplicably high source: Black & Veatch, LTPP Solar PV Performance and Cost Estimates, June 18, 2010, p. 14.
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Conclusions ď Ž
A 33% RPS portfolio will be more cost-effective in 2020 than a business-as-usual natural gas portfolio.
ď Ž
The most cost-effective 33% RPS portfolio will consist predominantly of distributed PV resources.
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