Energy DivisionCPUC

November 1, 2010

Self-Generation Incentive Program

Staff Proposal Workshop

The SGIP Staff Proposal Background

• Senate Bill (SB) 412: Authorizes the CPUC to determine what technologies to include in SGIP based on GHG reductions

• Jan 2010: Workshop held to take ideas on how to modify SGIP per SB 412

• Energy Division staff considered parties’ comments, conducted additional analyses, and developed recommendations on how to modify SGIP per SB 412

• Sept 2010 Ruling: Set schedule for filing written comments and issued the SGIP Staff Proposal with Energy Division’s preliminary recommendations

• Intent of this workshop is to solicit feedback from parties on inputs and recommendations prior to filing written comments

• No final decisions have been made regarding modifications to SGIP

SGIP Guiding Principles

1. SGIP should only support DER technologies that are cost-effective.

2. SGIP should only support technologies that produce fewer GHG emissions than they avoid from the grid.

3. SGIP incentives should provide sufficient payment to stimulate DER technology deployment without overpaying. SGIP incentives should not be provided to technologies that do not need them to earn a reasonable return on investment.

4. SGIP should support behind the meter “self-generation” DER technologies.

5. SGIP should only support commercially available technologies.

6. SGIP should target best of class DER by paying for performance.

7. SGIP incentives should focus on projects that efficiently utilize the existing transmission and distribution system.

8. SGIP should complement the structure of and be coordinated with existing ratepayer supported programs, especially the California Solar Initiative.

GHG Emissions Analysis

• Methodology: Expected lifecycle emissions of each DER technology are compared with emissions avoided by that technology:

Net Avoided Emissions = Avoided Emissions – Emissions ProducedDER

• Technologies with a positive Net Avoided Emissions pass the screen

• Technologies with a negative Net Avoided Emissions failed the screen

Natural Gas-fueled DER Methodology

Net Avoided Emissions = Avoided EmissionsElectricity + Avoided EmissionsHeat - Emissions ProducedDER

ARB Electricity Sector Emissions Assumptions

ARB Business as Usual (BAU) Avoided Emissions Rate

Avoided Emission Rate including 20% renewables used in this analysis

.437 TonneCO2/MWh .349 TonneCO2/MWh

• Natural gas technology assumptions:• Project Life - 10 years• Capacity Factor - 80%• Electrical Efficiency Degradation - 1% annually • Efficiency of avoided boiler (for CHP technologies) - 80%• Total System Efficiency Minimum Requirements = 62%• Conversion of natural gas to GHG emissions - 0.05317 Tonne CO2E/MMBTU

(conversion factor based on CO2E content of natural gas)• Line losses added to grid electricity avoided – 7.8%

• Industry supplied estimates used for electrical efficiency assumptions

Energy Storage DER Methodology

• Energy Storage technology assumptions:

• Efficiency Degradation - 1% annually

• Round trip efficiency was assumed to degrade by 1% per year

• Line losses – 7.8%

• Line losses were assumed both in charging and discharging

Grid Emissions Factors for Energy Storage

Charging – Off peak Discharging – On peak

.368 TonneCO2/MWh .575 TonneCO2/MWh

Net Avoided Emissions = EmissionsDischarging – EmissionsCharging

Gas Turbine

CapacityElectrical Efficiency

Total System

Efficiency (CHP only)

Heat Rate (calculated) Generation

T&D Avoided

Total Electricity Avoided

Emissions Avoided (E) Fuel Input

Natural Gas - GHG

ConversionEmissions Produced

Heat Recovered

Heat Recovery

RateEmissions Avoided (H)

Net Emissions Reduction

Technology Year MW % % BTU/kWh MWh MWh MWhTonne CO2E MMBTU

Tonne/MMBTU

Tonne CO2E MMBTU MMBTU

Tonne CO2E

Tonne CO2E

Gas Turbine 1 10 29.0% 62.0% 11,766 70,080 5,929 76,009 26,527 824,527 0.05317 43,842 272,094 46.5% 18,085 770

2 10 28.7% 62.0% 11,884 69,379 5,869 75,249 26,262 824,527 0.05317 43,842 274,485 46.7% 18,244 663 3 10 28.4% 62.0% 12,004 68,685 5,811 74,496 25,999 824,527 0.05317 43,842 276,852 46.9% 18,401 558 4 10 28.1% 62.0% 12,126 67,999 5,753 73,751 25,739 824,527 0.05317 43,842 279,196 47.1% 18,557 454 5 10 27.9% 62.0% 12,248 67,319 5,695 73,014 25,482 824,527 0.05317 43,842 281,516 47.3% 18,711 351 6 10 27.6% 62.0% 12,372 66,645 5,638 72,283 25,227 824,527 0.05317 43,842 283,813 47.5% 18,864 248 7 10 27.3% 62.0% 12,497 65,979 5,582 71,561 24,975 824,527 0.05317 43,842 286,087 47.7% 19,015 147 8 10 27.0% 62.0% 12,623 65,319 5,526 70,845 24,725 824,527 0.05317 43,842 288,338 47.9% 19,165 47 9 10 26.8% 62.0% 12,751 64,666 5,471 70,137 24,478 824,527 0.05317 43,842 290,567 48.1% 19,313 (52)

10 10 26.5% 62.0% 12,879 64,019 5,416 69,435 24,233 824,527 0.05317 43,842 292,773 48.3% 19,459 (150)

SubTotal (Sample Project) 10.000 27.7% 62.0% 12,315 670,090 56,689 726,779 253,646 8,245,274 0.05317 438,424 2,825,722 47.4% 187,814 3,0361 MW 1 27.7% 62.0% 12,315 67,009 5,669 72,678 25,365 824,527 0.05317 43,842 282,572 47.4% 18,781 304

Example: GHG Analysis for Gas Turbines

GHG Screening Results

Technology Fuel/Application GHG Reducing

Wind Turbines Wind Yes – Renewable

Fuel CellsNon-Renewable/Electric only

No – Except potentially on a per

product basis

Non-Renewable/CHP Yes

Renewable/Electric only or CHP Yes – Renewable

Gas TurbinesNon-Renewable/CHP Yes

Renewable/Electric only or CHP Yes – Renewable

Microturbines Non-Renewable/CHP

No*Except potentially on a per product

basis

Renewable/Electric only or CHP Yes – Renewable

Internal Combustion Engines

Non-Renewable/CHP – lean burnNon-Renewable/CHP – rich burn

Yes – lean burn No – rich burn

Renewable/Electric only or CHP Yes – Renewable

Organic Rankine Cycle Engines Waste Heat/Bottoming Cycle CHP Yes

Pressure-reduction Turbines Hydro/In-conduit Yes – Renewable

Advanced Energy StorageStand-alone Yes*

DG-integrated Yes

*Depends on the roundtrip efficiency and the assumption that storage offsets a combustion turbine on peak.

Technology Cost Analysis

Installed Costs

One time, up front capital costs

• Wind, FC, GT, ICE, and MT use SGIP data• Total cost divided by total capacity for each technology to

arrive at average $/W• Data used: completed projects through end of 2009

• Renewable fuel clean up – adder of $2,500/kW• Provided by California Bioenergy

• Waste heat, Organic Rankine Cycle, and Pressure reduction turbines• Provided by TAS, Waste Heat Solutions, and Zeropex

Technology Cost Analysis

On-going Costs

Operations & Maintenance (O&M)

• (O&M) costs provided by Itron in June, 2010• In the case of wind & CHP FCs, O&M figure which best

represented SGIP size projects was used• For example, Itron provided O&M figures for two sizes of wind turbines:

$0.002/kWh for a 10kW turbine, and $0.008/kWh for a 1MW turbine• CPUC uses the larger figure as it is more of SGIP projects

• In the case of GTs and ICEs, average of O&M figures used

• For example, Itron provided O&M figures for two sizes of GTs using NG: $0.021/kWh for a 1MW GT, and $0.017/kWh for 3.5MW GT

• CPUC uses the average of these two figures, $0.0195/kWh

Technology Cost Analysis

Performance Inputs

• Electrical Efficiency• Based on HHV provided by industry representatives via comments

• Performance Degradation• kWh production decreases at 1%/year, fuel consumption held constant

• Avoided electricity cost• PG&E’s A-10 TOU yearly average of $0.118/kWh used for 2010

• Utility price escalation• 2% is used, based on CEC data covering years 1982-2008

• Natural gas forecast• 2009 CA MPR used, stated in $/MMBtu for 2010-2020

• Overall efficiency of 62% (minimum)

Technology Cost Analysis

Financial Inputs

• Federal ITC• Applies to most technologies, shown as upfront capital payment

• Metering costs• Net electricity output ($4,300) • Waste heat capture ($17,000) • Fuel consumption ($7,500)

• Tariff based metering costs • Derived from PG&E’s A10-TOU

• Discount rate• 5% used as baseline

• Not included: Depreciation, salvage value

Example: CHP MT without incentivesTechnology Type Microturbine - CHP Installed Cost ($) $572,218Capacity (kW) 165 Installed Cost ($/kW) $3,293Incentive Amount - 1st MW ($/kW) $0 O&M ($/kWh) $0.020Incentive Amount - 2nd MW ($/kW) $0 ITC (%) 10.0%Incentive Amount - 3rd MW ($/kW) $0 Electrical efficiency 25.2%Incentive Payment in 1st Year 25% System efficiency 62.0%Incentive Payment Period (yrs) 5 Electricity cost ($/kWh) 0.12Discount Rate (%) 5.00% Metering Cost ($/yr) $1,439Degradation (%/yr) 1.00% Hours of operation/yr 8,760Utility price escalation (%/yr) 2.00% NG Cost ($/MMBtu) $6.20Capacity Factor 80.00% Boiler Efficiency 80%California Adder? Yes Heat Rate 13540

kW per Btu 3412

Year 1 2 3 4 5 6 7 8 9 10

Electricity generated (kWh) 1,156,320 1,144,757 1,133,309 1,121,976 1,110,756 1,099,649 1,088,652 1,077,766 1,066,988 1,056,318Value of avoided electricity $136,410 $137,747 $139,097 $140,460 $141,836 $143,226 $144,630 $146,047 $147,479 $148,924NG Consumed (MMBtu) 15,657 15,657 15,657 15,657 15,657 15,657 15,657 15,657 15,657 15,657Heat recovered (MMBtu) 5,762 5,704 5,647 5,591 5,535 5,479 5,425 5,370 5,317 5,263Heat recovery rate (%) 49.20% 48.71% 48.22% 47.74% 47.26% 46.79% 46.32% 45.86% 45.40% 44.94%Avoided NG consumption (MMBtu) 7,202 7,130 7,059 6,988 6,918 6,849 6,781 6,713 6,646 6,579Value of avoided NG $44,653 $50,196 $51,106 $51,433 $51,888 $52,465 $52,957 $53,502 $54,030 $54,542Cost of NG Consumed -$97,072 -$110,224 -$113,356 -$115,234 -$117,426 -$119,931 -$122,280 -$124,785 -$127,290 -$129,795O&M Costs -$23,126 -$22,895 -$22,666 -$22,440 -$22,215 -$21,993 -$21,773 -$21,555 -$21,340 -$21,126Metering Cost - Tariff Based -$1,439 -$1,439 -$1,439 -$1,439 -$1,439 -$1,439 -$1,439 -$1,439 -$1,439 -$1,439Metering Cost - Electricity output -$4,300Metering Cost - Waste heat -$17,000Metering Cost - Fuel consumption -$7,500SGIP Incentive Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0California Adder $0 $0 $0 $0 $0 $0 $0 $0 $0 $0ITC $33,000Cash Flow ($508,593) $53,384 $52,742 $52,780 $52,643 $52,327 $52,095 $51,769 $51,439 $51,105Cumulative Cash Flow ($508,593) ($455,208) ($402,466) ($349,686) ($297,043) ($244,715) ($192,620) ($140,851) ($89,411) ($38,306)

Net Present Value -$136,583IRR -1.55%Break Even (yrs) #REF!

Technology Cost Analysis Results

Outputs

TechnologyExpected

IRR (%)

Simple Payback (years)* NPV ($)

Wind Turbine 9.50% 9.66 $948,652Fuel Cell - Electric Only -13.78% #REF! -$429,149Fuel Cell - Electric Only (Biogas) -8.98% #REF! -$466,359Fuel Cell - CHP -8.81% #REF! -$1,010,713Fuel Cell - CHP (Biogas) -6.48% #REF! -$1,182,442Gas Turbine - CHP 13.47% 6.04 $727,227Gas Turbine - CHP (Biogas) 2.78% 8.93 -$395,359Microturbine - CHP -1.55% #REF! -$136,583Microturbine - CHP (Biogas) -11.91% #REF! -$549,218IC Engine - CHP 15.98% 5.62 $762,415IC Engine - CHP (Biogas) 2.81% 8.92 $1,978,345Organic Rankine Cycle 33.04% 3.83 $400,641Pressure Reduction 49.72% 2.98 $477,571

Hybrid Performance Based Incentive(Section 4.4.3)

Issue: • SGIP M&E studies have found that many projects have

not performed as expected.• Many projects have not maintained minimum efficiency

requirements during project life

• How can SGIP incentivize high-performing projects?

Recommendation:• Hybrid PBI:

• Upfront capacity payment = 25% of incentive• Annual performance payments = 15% of incentive paid for five

years

Declining Incentives Based on Market Penetration Volumes (Section 4.4.6)

Issue: • Declining incentives can facilitate market

transformation for DER technologies.• Declining incentive model has proven successful in

the CSI Program• Should a similar model be used in SGIP to further

encourage market penetration?

Recommendation:• Jan 1, 2012: SGIP decline by 10%• Incentives continue to decline each following

year by 10%

SGIP Budget Allocation amongst Technologies(Section 4.4.7)

Issue: • The current budget designations – “Level 2” and “Level 3” – are

outdated.• Based when the program included more technologies, such as solar

• Should the CPUC maintain carve-outs for renewable and non-renewable technologies?

Recommendations:• “Level 2” and “Level 3” designations should be eliminated and

replaced with “Renewable” and “Non-renewable” categories• Energy storage coupled with a renewable DG technology should be

funded out of the renewable budget category• All other Energy Storage projects should be funded out of the non-

renewable budget category

Metering Requirements (Section 4.5.2)

Issue: • Accurate metering and monitoring data is needed for

evaluation and PBI payment purposes

Recommendations:• All SGIP projects must install metering equipment that

records the following• 15-minute interval data on generation output• Fuel input (where applicable)• Heat output (for CHP)• System charging and discharging (for storage)

• All SGIP projects are required to provide interval data to the SGIP PAs on total energy consumption for project sites for a period of 5 years

Export of Electricity to the Grid (Section 4.5.4)

Issue: • Parties have proposed that SGIP technologies be able to

export electricity to the grid and also receive incentives

Recommendations:• Staff recommends against providing incentives that

export electricity on a net basis.• SGIP’s purpose is to facilitate self-generation that offsets

customer load.• For consideration:

• Allow SGIP projects to export a up to 25% of their output to the gird in order to optimize system sizing

• Allow Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT) program participants to receive SGIP incentives up to 1 MW

Maximum Reservation Hold Time(Section 4.5.6)

Issues:• A significant number of projects have held

reservations beyond the 18-month time limit• The SGIP PAs do not have a consistent process

for granting extensions

Recommendations:• The SGIP PAs should submit a quarterly report

listing all of the projects that exceeded the 18-month reservation time and list the reasons for the extensions

Application Fees (Section 4.5.7)

Issue:• Cancelled applications that re-apply for incentives create

additional processing work and administrative costs for the SGIP PAs• Currently, there is no dis-incentive for developers to cancel and

re-apply

For consideration:• Should there be an application fee for SGIP projects?• What would be an appropriate application fee scale?• Should the fee be a fixed amount or a percentage of the

total system cost?

Issues for Additional Consideration (Section 4.5.8)

Issue 1: Wind Turbines and Coordination with ERP• To date, only 6 SGIP wind projects have been completed• The CEC’s Emerging Renewables Program (ERP) has provided the

vast majority of incentives for wind projects (466 projects)

For Consideration: • Consolidate the wind turbine incentives into one program in

coordination with the CEC

Issue 2: Budget Carve-out for Competitive Grants• SGIP incentives may not be the best mechanism to promote the

adoption of less commercially advanced technologies

For consideration:• Dedicate funds from the SGIP budget for a competitive grant

program for less advanced technologies

Cost-Effectiveness Model

Wrap-up and Next Steps

• Comments due November 15th

• Formal written comments on the Staff Proposal are filed and submitted to the CPUC Service List “R.10-05-004”

• Reply comments are due December 1, 2010

• Informal comments on the Cost-Effectiveness model are due to Itron (not filed with the CPUC Process Office)

• Cost-Effectiveness comments should be sent via email to the following:

• Chuck Hornbrook (Chuck.Hornbrook@itron.com)• George Simons (George.Simons@itron.com) • Neal Reardon (nmr@cpuc.ca.gov)• Melicia Charles (mvc@cpuc.ca.gov)