ATTACHMENT B: APPENDIX C
SELECTED STATEWIDE COST-EFFECTIVENESS
INPUT VALUES

The CBEE recommends the CPUC direct interim administrators to rely on statewide cost-effectiveness input values for:

1.  Avoided electricity generation
2.  Avoided transmission and distribution costs and loss factors
3.  Avoided natural gas consumption by end users
4.  Avoided environmental externalities

This attachment summarizes the CBEE’s recommendations for these values and compares the recommended values for electricity to those used by the interim administrators in PY98.  T&D loss factors have already been included in the recommended avoided electricity generation values and so are not reported separately.  

     Summary of CBEE Recommended Input Values for PY99 Cost-Effectiveness Evaluation

	Gen	T&D	Env Ext	Total		Gas	Env Ext	Total	
	$/MWh	$/MWh	$/MWh	$/MWh		$/therm	$/therm	$/therm	
1999	33.1	4.7	6.0	43.8		0.319	0.053	0.372	
2000	34.1	4.9	6.2	45.2		0.330	0.055	0.385	
2001	34.9	5.1	6.4	46.4		0.339	0.056	0.395	
2002	37.2	5.3	6.6	49.0		0.348	0.058	0.406	
2003	38.5	5.5	6.8	50.8		0.358	0.060	0.418	
2004	40.0	5.7	7.0	52.8		0.369	0.062	0.431	
2005	41.5	6.0	7.2	54.7		0.380	0.063	0.443	
2006	43.3	6.2	7.4	56.9		0.391	0.065	0.456	
2007	45.0	6.5	7.6	59.1		0.404	0.067	0.471	
2008	46.8	6.8	7.9	61.4		0.416	0.069	0.485	
2009	48.7	7.0	8.1	63.9		0.429	0.071	0.500	
2010	50.8	7.3	8.3	66.5		0.442	0.073	0.515	
2011	53.0	7.6	8.6	69.2		0.452	0.076	0.528	
2012	55.3	7.9	8.8	72.1		0.461	0.078	0.539	
2013	57.7	8.3	9.1	75.1		0.472	0.080	0.552	
2014	60.2	8.6	9.4	78.2		0.482	0.083	0.565	
2015	62.7	9.0	9.7	81.4		0.493	0.085	0.578	
2016	65.4	9.3	9.9	84.7		0.504	0.088	0.592	
2017	68.2	9.7	10.2	88.2		0.516	0.090	0.606	
2018	71.1	10.1	10.5	91.8		0.528	0.093	0.621	

     Comparison of Avoided Electricity Costs Projections

This table compares the avoided electricity costs (including avoided generation, avoided T&D, losses, and avoided environmental externalities) recommended by the CBEE to those used by the interim administrators in PY98.   The comparison information is taken from the utilities’ 1998 annual DSM summary reports.  Interim administrators worked with CBEE’s TSC to express the values in a manner that would facilitate comparison to the CBEE’s recommended values. 

Comparison of Electricity Avoided Costs ($/MWh)	
						
	CBEE		PG&E	SCE	SDG&E	
						
1999	43.8		69.0	44.2	47.3	
2000	45.2		71.1	45.5	48.7	
2001	46.4		73.2	46.9	50.2	
2002	49.0		75.4	48.3	51.7	
2003	50.8		77.7	49.7	53.3	
2004	52.8		80.0	51.2	54.9	
2005	54.7		82.4	52.8	56.5	
2006	56.9		84.9	54.4	58.2	
2007	59.1		87.4	56.0	59.9	
2008	61.4		90.1	57.7	61.7	
2009	63.9		92.8	59.4	63.6	
2010	66.5		95.5	61.2	65.5	
2011	69.2		98.4	63.0	67.5	
2012	72.1		101.4	64.9	69.5	
2013	75.1		104.4	66.9	71.6	
2014	78.2		107.5	68.9	73.7	
2015	81.4		110.8	70.9	75.9	
2016	84.7		114.1	73.1	78.2	
2017	88.2		117.5	75.2	80.6	
2018	91.8		121.0	77.5	83.0	
						
Sources	Mike Wan, PG&E (10/5/98)					
	Tory Weber, SCE (10/5/98)					
	Athena Besa, SDG&E (10/5/98)					

 1.  Avoided Electricity Generation

The CBEE’s recommended value for avoided electricity generation is based on three elements: 1.  Avoided generation energy costs; and 2. Avoided generation capacity costs.  A third element, avoided T&D losses, is also included because it is by convention linked to avoided generation costs.  

The CBEE bases its recommendation for the value of avoided generation and avoided long-run generation capacity costs on the CEC’s forecast of electricity market clearing prices from California’s new competitive electricity generation market.  Prices set in this market now establish the value of electricity generation.

The CBEE bases its recommendation for the value of avoided short-run generation capacity costs on prices of ancillary services used by the ISO as well as those developed through the PX.  Ancillary services consist of a variety of electricity services needed to ensure reliability (such as spinning reserve).  Many of these prices are fixed for generators byFERC approved tariffs; others, for a selected number of generators, are set through a market that is conducted by the PX.  The prices for ancillary services typically range between $5-8/MWh (0.5-0.8 cents/kWh).  Last summer, FERC allowed the ISO to cap market prices at $250/MWh as a result of market instability.  The recommend $5/MWh, escalated at a 3%/year, is a conservative estimate of cost of ancillary services.

The CBEE reviewed information provided by the utilities on T&D loss factors.  Values range from about 7% to over 10% (for on-peak capacity).  The recommend 7% is a conservative measure of T&D losses. 

	Mkt Clear	MCP	Ancillary	AS		Avd Cost	
	Price	escalation	Services	escalation	Losses	Gen	
	$/MWh		$/MWh			$/MWh	
1999	25.9		5.0		7%	33.1	
2000	26.7	3.2%	5.2	3%	7%	34.1	
2001	27.4	2.4%	5.3	3%	7%	34.9	
2002	29.3	7.0%	5.5	3%	7%	37.2	
2003	30.3	3.7%	5.6	3%	7%	38.5	
2004	31.6	4.2%	5.8	3%	7%	40.0	
2005	32.8	3.8%	6.0	3%	7%	41.5	
2006	34.3	4.4%	6.1	3%	7%	43.3	
2007	35.7	4.2%	6.3	3%	7%	45.0	
2008	37.3	4.3%	6.5	3%	7%	46.8	
2009	38.8	4.2%	6.7	3%	7%	48.7	
2010	40.6	4.5%	6.9	3%	7%	50.8	
2011	42.4	4.5%	7.1	3%	7%	53.0	
2012	44.3	4.5%	7.3	3%	7%	55.3	
2013	46.4	4.6%	7.6	3%	7%	57.7	
2014	48.4	4.5%	7.8	3%	7%	60.2	
2015	50.6	4.5%	8.0	3%	7%	62.7	
2016	52.9	4.5%	8.3	3%	7%	65.4	
2017	55.2	4.5%	8.5	3%	7%	68.2	
2018	57.7	4.5%	8.8	3%	7%	71.1	

2.  Avoided Transmission and Distribution Costs

The CBEE weighted forecasts of avoided T&D costs by 1996 sales for each utility to develop a recommended statewide average.  The CBEE converted the values from $/kW to $/MWh by assuming a 0.6 load factor.

96 sales	73.318		15.981		73.785					
save wght	0.45		0.10		0.45				load factor	
									0.6	
	PG&E		SDG&E		SCE		Wght Ave			
	$/kW	escalation	$/kW	escalation	$/kW	escalation	$/kW	escalation	$/MWh	
1999	44.7		12.7		7.4		24.7		4.69	
2000	46.6	4.3%	13.1	3.3%	7.6	3.5%	25.7	4.1%	4.88	
2001	48.6	4.3%	13.6	3.2%	7.9	3.5%	26.7	4.1%	5.09	
2002	50.7	4.3%	14.0	3.2%	8.1	3.5%	27.8	4.1%	5.29	
2003	52.8	4.3%	14.5	3.4%	8.4	3.5%	29.0	4.1%	5.51	
2004	55.1	4.3%	15.0	3.5%	8.7	3.5%	30.2	4.1%	5.74	
2005	57.4	4.3%	15.5	3.5%	9.0	3.5%	31.4	4.1%	5.98	
2006	59.9	4.3%	16.0	3.5%	9.4	3.5%	32.7	4.1%	6.23	
2007	62.5	4.3%	16.6	3.5%	9.7	3.5%	34.1	4.1%	6.48	
2008	65.1	4.3%	17.2	3.5%	10.0	3.5%	35.5	4.1%	6.75	
2009	67.9	4.3%	17.8	3.4%	10.4	3.5%	37.0	4.1%	7.03	
2010	70.8	4.3%	18.4	3.4%	10.7	3.5%	38.5	4.1%	7.32	
2011	73.8	4.3%	19.0	3.5%	11.1	3.5%	40.1	4.1%	7.63	
2012	77.0	4.3%	19.7	3.5%	11.5	3.5%	41.7	4.1%	7.94	
2013	80.3	4.3%	20.3	3.3%	11.9	3.5%	43.5	4.1%	8.27	
2014	83.7	4.3%	21.0	3.3%	12.3	3.5%	45.3	4.1%	8.61	
2015	87.3	4.3%	21.7	3.3%	12.7	3.5%	47.1	4.1%	8.97	
2016	91.0	4.3%	22.4	3.3%	13.2	3.5%	49.1	4.1%	9.34	
2017	94.9	4.3%	23.2	3.3%	13.7	3.5%	51.1	4.1%	9.73	
2018	99.0	4.3%	24.0	3.4%	14.1	3.5%	53.2	4.1%	10.13	
										
Sources:	Mike Wan (10/1/98)  PG&E System Average Capacity Values ($/kW-yr) for DSM Evaluation									
	Athena Besa (10/2/98)  Avoided T&D Costs									
	Don Arambula (9/9/98)  1999 Avoided Costs for Retrofit Programs T&D Value $/kW-yr									

3.  Avoided Natural Gas Costs

The CBEE reviewed information developed by PG&E and SCG on avoided gas costs.  SDG&E recommended SCG’s values as representative of SDG&E avoided gas costs.  The CBEE weighted the two cost streams using core gas sales for each company to develop a recommended statewide average.

96 core sales	2.7		3.1				
Saleswght	0.46		0.54		Avoided		
	PG&E		SCG		Gas		
	$/therm	escalation	$/therm	escalation	$/therm	escalation	
1999	0.311		0.326		0.319		
2000	0.320	2.9%	0.338	3.7%	0.330	3.3%	
2001	0.329	2.8%	0.348	3.0%	0.339	2.9%	
2002	0.338	2.7%	0.357	2.6%	0.348	2.7%	
2003	0.348	3.0%	0.367	2.8%	0.358	2.9%	
2004	0.359	3.2%	0.378	3.0%	0.369	3.1%	
2005	0.369	2.8%	0.389	2.9%	0.380	2.9%	
2006	0.380	3.0%	0.401	3.1%	0.391	3.0%	
2007	0.392	3.2%	0.414	3.2%	0.404	3.2%	
2008	0.403	2.8%	0.427	3.1%	0.416	3.0%	
2009	0.416	3.2%	0.440	3.0%	0.429	3.1%	
2010	0.428	2.9%	0.455	3.4%	0.442	3.2%	
2011	0.442	3.3%	0.461	1.3%	0.452	2.2%	
2012	0.455	2.9%	0.467	1.3%	0.461	2.0%	
2013	0.469	3.1%	0.474	1.5%	0.472	2.2%	
2014	0.483	3.0%	0.481	1.5%	0.482	2.2%	
2015	0.499	3.3%	0.488	1.5%	0.493	2.3%	
2016	0.514	3.0%	0.495	1.4%	0.504	2.2%	
2017	0.530	3.1%	0.503	1.6%	0.516	2.3%	
2018	0.547	3.2%	0.511	1.6%	0.528	2.4%	
							
Sources:	PG&E Residential Distribution Level Avoided Cost						
	SCG Core Customer Avoided Cost Winter Peaking						

4.  Avoided Electricity and Gas Externality Adders

The CBEE developed recommended environmental externality adders for electricity and gas use based on CEC-recommended values for individual pollutants.  Specifically, the CEC does not recommend reliance on values developed by CEC for ER94, but instead values based on recent experience from California markets were permits for these pollutants are traded.  The one exception is carbon, which is not traded; CEC continues to recommend $30/ton.  

The CBEE converted the CEC recommended values to $/MWh and $/therm using conversion factors developed by the CEC and SCG.   The electricity conversion factors are consistent with the methods used by the CEC to develop its forecast of market clearing prices.  Both values are escalated at an assumed inflation rate of 3%/yr.

CEC Air Emissions Externality Values for Program Portfolio
Cost-Effectiveness Calculations (9/28/98)								
								
Pollutant	1999 $/ton							
SOx	1780							
NOx	1800							
VOC	530							
PM10	910							
C	30							
								
Electricity Environmental Externality Adder								
								
Emission Factors (lb/kWh)								
	Gas Stm	($/MWh)	Gas CT	($/MWh)	Gas CC	($/MWh)		
SO2	1.08E-05	0.0	6.96E-04	0.6	1.44E-04	0.1		
NOx	2.46E-04	0.2	4.15E-04	0.4	8.00E-06	0.0		
VOC	3.28E-05	0.0	2.72E-04	0.1	6.40E-05	0.0		
PM10	3.66E-05	0.0	2.57E-04	0.1	1.04E-04	0.0		
C	0.333	5.0	0.469	7.0	0.264	4.0		
		5.2		8.2		4.2		
								
Percent Time Generator is Setting Market Clearing Price								
		0.6		0.2		0.2		
								
Adder	$/MWh	5.6						
w/losses	7%	6.0						

Natural Gas Environmental Externality Adder								
								
Emission Factors (lb/therm)								
		($/therm)						
NOx	4.50E-03	0.004						
PM10	7.10E-04	0.000						
C	3.245	0.049						
								
Adder	$/therm	0.053						

Escalate Adders Over Time								
	Electricity	Natural Gas	escalation					
1999	6.0	0.053						
2000	6.2	0.055	3%					
2001	6.4	0.056	3%					
2002	6.6	0.058	3%					
2003	6.8	0.060	3%					
2004	7.0	0.062	3%					
2005	7.2	0.063	3%					
2006	7.4	0.065	3%					
2007	7.6	0.067	3%					
2008	7.9	0.069	3%					
2009	8.1	0.071	3%					
2010	8.3	0.073	3%					
2011	8.6	0.076	3%					
2012	8.8	0.078	3%					
2013	9.1	0.080	3%					
2014	9.4	0.083	3%					
2015	9.7	0.085	3%					
2016	9.9	0.088	3%					
2017	10.2	0.090	3%					
2018	10.5	0.093	3%