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PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION RESOLUTION E - 3980

RESOLUTION

__________________________________________________________

SUMMARY

2005 MPR values have been calculated for use in the 2005 Renewables Portfolio Standard (RPS) solicitations.

This Resolution formally adopts the 2005 MPR values for a baseload proxy plant for the use in the 2005 RPS solicitations. This Resolution is made on the Commission's own motion.

The 2005 MPRs in the table below reflect MPR values calculated pursuant to D.04-06-015, D.05-12-0421, and Staff recommendations.

BACKGROUND

Release of 2005 MPRs is consistent with prior Commission decisions

In D.04-06-015, we adopted a methodology to calculate MPRs for use in the 2004 renewable power solicitations, as generally set forth in Pub. Util. Code §§ 399.11-399.16.2 D.04-06-015 set forth the following process under which MPRs would be disclosed:

"[W]e conclude that the MPRs should be publicly and simultaneously disclosed to all parties after bidding has closed, but before completion of the utility's final short list. The MPR will be available to parties before negotiations are complete, to allow additions to the tentative short list, and the informed negotiation of payment streams. In order to implement this approach, each utility must notify the Commission via letter to the Executive Director that bidding has concluded, and that the utility expects to complete its tentative short list by a specified date. The Commission will coordinate the public and simultaneous disclosure of the MPR to all parties with this information in mind. After the parties have negotiated and finalized their bids based on subsequent release of the MPR, each utility will submit its final short list of bidders to the Commission staff and its PRG.3"

In addition, D.04-06-015 directed staff to prepare the MPR calculation and release it through a joint Assigned Commissioner and Administrative Law Judge (ALJ) ruling. Parties filed comments and reply comments on the staff report releasing the MPR calculation. Staff then prepared a resolution for the adoption of the final MPR for 2004.

In view of the extensive work on the 2004 MPR and the more extensive record given careful consideration by the parties for the outstanding issues for the 2005 MPR, D.05-12-042 determined that a simpler process may be used now. D.05-12-042, modified by D.06-01-0294, directs staff to prepare a draft resolution on the 2005 MPR, including any relevant supporting materials as attachments to the draft resolution.

The draft resolution will be released after all utility solicitations have been closed. Parties will have the usual opportunity to file comments and reply comments on the draft resolution prior to its formal consideration by the Commission. 5

The three IOUs submitted their letters to the Executive Director notifying the Commission that their solicitations were closed and the preliminary short-lists were complete:

DISCUSSION

MPRs Were Calculated Using a Cash-Flow Simulation Methodology

The MPRs shown above were calculated using the Southern California Edison (SCE) MPR model, a cash-flow simulation methodology approved by the Commission in D.04-05-015 and modified by Resolution E - 3942.9 The SCE MPR model calculates what it would cost to own and operate a power plant over a 20-year period. The cost of electricity generated by such a power plant, at an assumed capacity factor and set of costs, is the proxy for the long-term market price of electricity.

The MPR model requires several types of input data, including natural gas prices, capital costs, operating costs, finance costs, taxes, and power delivery assumptions. The primary input drivers for the MPR calculation are the California (CA) gas price forecast, power plant capital costs, and the capacity factor for the baseload MPRs.

Note - Staff calculated the 2004 MPRs using the SCE Cash-Flow model and output from the MPR Gas Forecasting model. For 2005 and beyond, the two models have been merged together into one model, which Staff refer to in this resolution as the "MPR model."

MPR Based on CT Will no Longer be Calculated

In 2004 Staff calculated an MPR for a CCGT (baseload) and CT (peaker) proxy plant. In their 2005 MPR comments, PG&E and several other parties recommend that an MPR based on a peaking proxy unit not be adopted for use in 2005. Rather, the MPR for peak period energy should be established by applying factors derived through the TOD methodology to the baseload MPR. The application of TOD factors to the baseload MPR would eliminate the combustion turbine (CT) - based peaking MPR and the "blended" off-peak MPR (adopted in D.04-07-029).

PG&E noted that its proposal did not conflict with the statutory direction to establish a methodology to determine the MPR in consideration of "the value of different products including baseload, peaking, and as-available output."10 TOD factors are based on the forward value of electricity during different TOD periods. Output from baseload, peaking, and as-available units may be time-differentiated by these periods, so the application of TOD factors to the MPR will result in a market price for each product and electric generating unit. Thus, it was not necessary to separately adopt an MPR based on the cost of an electric generating unit operated only during periods of peak demand.

D.05-12-042 agreed with PG&E that the application of TOD factors to the baseload MPR did take into account "the value of different products including baseload, peaking, and as-available output." Nothing in the statute requires the Commission to use multiple plant proxies in order to do so. Thus, D.05-12-042 ordered Staff to no longer calculate a CT-specific MPR based on the cost of an electric generating unit operated only during periods of peak demand.

MPR Gas Forecast Methodology and Inputs

D.04-06-015 noted that there is no transparent, liquid market for natural gas forward products for 10, 15 or 20-year terms, which is necessary in order to fuel a proxy power plant producing fixed-priced electricity over these time periods. Consequently, D.04-06-015 outlined a California gas forecasting methodology for years 1 through 6, and another methodology for years 7 through 20, both of which are based on the forward Henry Hub (HHub) gas price that is basis adjusted to California.11

D.05-12-042, modified by D.06-01-029, refined the methodology for years 1- 6 by changing the 60-day-averaging period for the NYMEX forward prices to a 22-trading day averaging period, ending with the close of the utilities' solicitations.12 For years 7 - 20, D.05-12-042 noted that parties criticized the methodology used in 2004 as not yielding consistent and explainable results using data from a variety of time periods and market conditions. Most notably, the gas prices for Years 7-20 were heavily (possibly too heavily) influenced by the forward gas price in the last year of NYMEX data used in the 2004 MPR forecast.

Consequently, D.05-12-042 adjusted the relationship between the end of NYMEX data (no later than Year 6, and possibly Year 5, see D.04-06-015) and the beginning of reliance on the fundamentals forecasts in Year 7 to address the problems with the forecast in 2004. D.05-12-042 determined that, instead of using the escalation forecasting methodology of the 2004 MPR for Years 7-20, Staff should use a three-year straight line blending between the near-term (Years 1-6) and the long-term (Years 7-20), and then use the average of the fundamental forecasts for the remaining years. This method retains the absolute value of the fundamentals-based gas price forecasts and eliminates the escalation process for Years 7-20 that we used in 2004, which was the subject of criticism from the parties.

The fundamental forecast for years 7 - 20 was developed using two private and one public 20-year Henry Hub fundamental forecasts13. Specifically, the public forecast was based on the HHub wellhead prices provide in the U.S. Energy Information Administration (EIA) 2006 Annual Outlook14. With regard to the two private forecasts, they are a private sector natural gas forecasts from Cambridge Energy Research Associates (CERA), PIRA Energy Group, or Global Insight. Due to contractual obligations requiring the CPUC to keep the forecast confidential, staff can not reveal which of the three firms the forecasts were purchased from.

It should be noted that the EIA HHub forecast is derived by manipulating the EIA's forecasted wellhead prices. Specifically, EIA examined the relationship between Henry Hub spot prices for natural gas and the U.S. wellhead price for the period spanning August 1996 through December 200015. Their analysis determined the extent to which the two price series are linearly correlated and also evaluated the statistical properties of two simple price relationships-the actual difference and the percent difference. The results of the analysis indicated that there was a strong linear relationship between the two price series, to the effect that, on average the Henry Hub spot prices were 32 cents per thousand cubic feet (10.8 percent) higher than wellhead prices. The median value of the actual difference is 24 cents per thousand cubic feet, and the median value of the percent difference is 10.4 percent. Consequently, staff escalated the EIA wellhead prices by 10.8% to derive a proxy HHub forecast.

Please refer to:

MPR Non-Gas Methodology and Inputs

Cost of Capital

Most parties,16 with the exception of SCE, were critical of the financing assumptions used in the 2004 MPR. They asserted that those assumptions were internally inconsistent, having combined a merchant plant capital structure (70% debt/30% equity) with typical utility rates of interest on debt and return on equity. To address this concern in 2005, the Commission asked the parties to comment on three related aspects of the capital structure and cost of the proxy plant: financing of the proxy plant (project-based or total balance sheet); cost of capital for a proxy plant having a long-term PPA with a creditworthy IOU (same as IOU or different); and development of a specific weighted average cost of capital for a proxy plant having a long-term PPA with a creditworthy IOU.17

Based on several stakeholder meetings and party comments, D.05-12-042 adopted the following methodology for determining the financial inputs for the 2005 MPR:

2005 MPR WACC

 

DE Ratio

Cost

After-Tax

Debt

43.0%

8.03%

2.02%

Common Stock

58.0%

12.68%

7.29%

WACC

-

-

9.31%

Heat Rate Adjustments

D.05-12-042 instructed staff to gather information from the manufacturer about the General Electric (GE) "F" series turbine, as well as information about the operation of California power plants, to determine how to adjust the 2005 MPR heat rate to reflect heat rate degradation, dry cooling, and start/stops. Staff selected the S207FA F-Series Turbine20 from GE as the starting point for determining the operating heat rate.

Gas turbine degradation usually happens gradually over time, the net effect is that heat rate decreases over time. The root causes include deposit of airborne material - particularly silica - on turbine blades at high temperature, erosion/corrosion of blading due to other airborne salts - particularly sodium, maintenance practices such as regular blade washing - on line or offline, number of starts and operating hours.

Heat rate degradation can be classified as recoverable or non-recoverable loss. Recoverable loss is usually associated with compressor fouling and can be partially rectified by water washing or, more thoroughly, by mechanically cleaning the compressor blades and vanes after opening the unit. Non-recoverable loss is due primarily to increased turbine and compressor clearances and changes in surface finish and airfoil contour. Because this loss is caused by reduction in component efficiencies, it cannot be recovered by operational procedures, external maintenance or compressor cleaning, but only through replacement of affected parts at recommended inspection intervals. Quantifying performance degradation is difficult because consistent, valid field data is hard to obtain.

For the 2004 MPR, the Commission adopted a 3.5% heat rate degradation factor recommended by the parties. In its 2005 MPR comments, SCE recommended that Staff contact the manufacturer for a specific heat rate degradation factor. Using a heat rate degradation equation provided by GE, 21 Staff calculated the average heat rate degradation per hour of plant operation and adjusted the heat rate appropriately. Note - the average heat rate degradation factor, over the life of the plant, is 1.7%. This value assumes normal maintenance and off-line compressor water wash of the CC turbine and a major overhaul is conducted every 6 years (45-48,000 hrs), which brings the CC back to almost "new & clean".

Dry cooling is the second heat rate adjustment that D.05-12-042 required Staff to research and calculate. In its 2005 MPR comments (pg.6), CalWEA stated:

SCE disagreed with CalWEA's proposed HR adjustment in its reply comments (pg.6), claiming that the adjustment is a function of plant location. Staff agrees with SCE that the impact of dry cooling on heat rate is largely driven by ambient temperature. However, given that the majority of CA's plants are being built inland, i.e., not desert or coastal locations, Staff made a simplifying assumption that the 1.5%22 increase in heat rate for Sutter is an appropriate value use for the 2005 MPR. The adoption of this value is supported by the rule-of-thumb adjustment (1.5%) recommended by GE for F-series turbines with dry cooling.23

Lastly, with regards to the Start/Stop impact on heat rate, parties noted that using a capacity factor lower than 92% will have an impact on the achieved heat rate, because the proxy plant will have less efficient operation when starting and stopping more frequently. Other parties agreed that the lower capacity factor could affect heat rate. Because we did not have quantitative information about the effect of lower capacity factor on heat rate, D.05-12-042 instructed Staff to collect information about the impact of a lower capacity factor on heat rate, and include such information, if relevant, in the staff calculation and supporting materials for the 2005 MPR draft resolution.

Staff contacted GE for a recommendation and was informed that without doing production cost modeling, 100 - 150 starts/year was an appropriate proxy value to use. This value assumes a must-run plant with a capacity factor between 85% - 92% capacity factor. Consequently, Staff selected 125 as a mid-point. For start-up fuel cost (MMBtu/MW), Staff used a value of 2.8 MMBtu/MW, which is based on CEC production cost modeling data (8/31/05). See Heat_Rate Tab in the 2005 MPR model for the specific calculation.

Capacity Factor

A critical issue raised by the parties is whether the MPR should continue to use the capacity factor of 92% adopted in 2004. This capacity factor assumes that the proxy plant is running essentially all the time, and captures the effects of both maintenance and unplanned outages. D.05-12-042 agreed with the IOUs that a developer with a fixed-price must-run contract, paid a levelized price, would find it economic to run in all hours, operate at full load in all hours, and can recover its fixed costs at a price that assumes the maximum feasible amount of generation.

However, D.05-12-042 points out that the introduction of Time of Delivery (TOD) profiles provide the generators with a market pricing signal. The generator is now paid a different $/kWh/TOD period depending on when it generates. The end result is that the generator will not operate in hours where its marginal costs are greater than its marginal profits, which will be something below 92% of the time.

Consequently, D.05-12-042 ordered Staff to calculate the capacity factor for the MPR CCGT by computing a capacity factor based on each utility's TOD profile and then averaging the three MPR capacity factors to arrive at a statewide average capacity factor to be used in the final MPR calculation. This approach embraces the "market behavior" approach because we would be modeling what the owner of a new CCGT would do if it contracted with a California IOU.

The TOD capacity factor calculation developed by Staff determines the periods in which the TOD factor results in an MPR that is below the plant's variable operating costs.

When operating revenues for a TOD period are below both the variable operating costs and start up costs, it is assumed that the plant will shut down for all the hours in that period. The variable operating costs are assumed to be the levelized MPR variable component calculated by the MPR model. Start-up costs are based on a fuel use of 2.8 MMBtu/MW or roughly $10,000 depending on the levelized price of natural gas over the MPR contract period.

The calculation starts with an assumed technical capacity factor of approximately 92%: in this case the fixed costs for the referent plant are allocated over 92% of the year, or 8,087 hours. The calculation then estimates the number of hours the plant will shut down for economic reasons and calculates the resulting capacity factor, which may be lower, but not higher, than the technical capacity factor. If the capacity factor is lower, the fixed costs will be allocated over fewer hours (i.e. 88% or 7,735 hours). Thus, the lower capacity factor results in a higher MPR. The higher MPR in turn may reduce the number of hours that the plant shuts down, resulting in a higher capacity factor. Therefore, it is necessary to run the calculation iteratively until the result becomes stable or alternates between a higher and lower capacity factor. In the later case, the final result is the average of the high and low capacity factor. The MPR Cash Flow Model is designed to iterate the calculation five times.

Calculating an economic capacity factor using TOD's is, by definition, a non-continuous or 'step' function. A plant is assumed to be on or off for all hours in a given TOD period (The off-peak periods with the lowest TOD factors total between 736-2,032 hours, or 8-23% of the year). In addition, the TOD's for off-peak periods may result in MPR's that are very close to the variable operating costs. Both these factors result in a capacity factor calculation that may be very sensitive to a change in the fixed cost, start up cost and TOD factor inputs. See the Cap_Fac Tab in the 2005 MPR model for the specific calculation

Baseload Capital Costs

The 2004 MPR was based on the CEC Cost of Generation Report's estimate of $616/kW (2004$) for installed capital costs. Using the CEC's Cost of Generation model, Energy Division calculated a value of $720/kW for the CCGT baseload resource, making adjustments for interconnection costs, environmental permitting costs (aside from emissions), additional capital costs for dry cooling, and contingency costs.

However, in 2005, several parties recommended that the Commission use values that reflect the actual cost of a range of CCGT projects that have been built in the last few years or are currently under construction in California. TURN further argued that the Commission should not use the current market survey data obtained from the Energy Commission's application for certification (AFC) process (input for CEC's Cost of Generation Model), but should only use actual data from operating projects after initial commercial operations, or from those under construction, and subject to independent audit.

D.05-12-042 adopted the above recommendation that the market survey of plants most recently constructed or currently under construction should be used when identifying specific input values. 24 D.05-12-042 also adopted additional criteria for conducting a market survey of plant costs. Specifically, Staff was ordered to use the following as suggested criteria in selecting plants to survey:

Staff identified the installed capital costs for the 2005 MPR CCGT proxy using the reported capital costs ($ per kW) of comparable CCGT plants. To find comparable plants, Staff started with the list of existing and planned CCGT plants within the Western Electricity Coordinating Council (WECC) found on the CEC's "Energy Facility Status" website.25 Using the survey criteria outlined above, Staff identified the following plants that had publicly available cost data:

Based on the plants listed above the average installed capital cost, reflecting interconnection costs, environmental permitting costs (aside from emissions), additional capital costs for dry cooling, and contingency costs is $885/kW (2006$). Please refer to Appendix C for a detailed discussion regarding how the installed capital cost for the 2005 MPR was derived.

Fixed and Variable O&M Costs

In its reply comments (pg. 9), PG&E stated that the SCE Benchmark Study of Operation and Maintenance (O&M) values sponsored by SCE witness Joe Wharton before the FERC on behalf of Edison in the Mountainview case contains a wide range of O&M values and provides a reliable starting point for the Commission's quantification of O&M costs.26 PG&E and CalWEA also agreed that the survey should be augmented by the Palomar O&M data. However, PG&E recommended discarding the extreme high and extreme low values, that is, the fixed O&M values for EOB of $36.09/kW-yr and for Mountainview of $8.70/kW-yr. Giving each remaining source (plus Palomar) equal weight, the final fixed O&M value should be $13.92 / kW-yr.

Staff adopted PG&E's proposal with modifications:

2005 MPR Fixed and Variable O&M

Data Source

Fixed O&M (2006$)

Variable O&M (2006$)

Palomar

13.84

3.18

CC8

14.94

1.84

2006 EIA

11.01

3.29

Henwood

10.41

2.08

CERA

16.01

1.07

CEC

16.01

2.54

Stone & Webster

N/A

3.01

Average

$13.70

$2.43

Additional Modifications to the 2004 MPR Methodology

1. Nominal MPRs Reflecting Different Project On-line Dates

In their 2005 MPR comments, CalWEA group, SCE, PG&E, and SDG&E agreed that the MPR should be calculated in nominal dollars28 for at least two reasons. The bid prices of projects are expressed in nominal dollars. In addition, since the utility is guaranteed recovery of renewable power purchase costs at or below the MPR, there should be no ambiguity regarding the comparison of bid prices with the MPR.29 The parties30 also agreed that it was beneficial for the Commission to calculate a series of MPRs for different project on-line dates. Since bidders express their final contract prices in nominal dollars, and projects may require several years' lead time before deliveries begin, the Commission should calculate a series of MPRs corresponding to different project on-line dates in 2006 through 2010.

Consequently, D.05-12-042 reaffirmed the approach of calculating nominal MPRs reflecting different project on-line dates, as original adopted in Resolution E-3942.31 So, for the 2005 MPR calculation, Staff assumed that after the 5-year period (after 2010), technological improvements would offset the escalation of capital costs, so no further adjustment due to inflation was required. Pursuant to D.05-12-042, the 2006 - 2010 capital costs were escalated using a specific inflation index focused on changes in the cost to construct plants.32 See CF_Data Set Tab in the 2005 MPR model for the specific calculation

2. Straight-line depreciation for property tax

Per D.05-12-042, Staff adopted the straight line method as a simplifying assumption for the property tax calculation for the proxy plant. See Fixed_Comp Tab in the 2005 MPR model for the specific calculation.

3. GMM - 20-Day Average vs. 365-Day Average

In its 2005 comments, CalWEA asserted that the assumption in the 2004 MPR of a 98.57% Generation Meter Multiplier (GMM), should be revised. This value was derived from a sample of generator GMMs from a two-week period in December 2004. The CalWEA group noted that GMM values can be much higher during the summer months, when the transmission system is more heavily loaded. Because the utilities track the CAISO's system average GMM on a daily basis, they possess the data needed to calculate system average GMMs for all generators on the CAISO grid, over all days of the year.

The CalWEA group therefore recommended using these system average GMM values for 2004 in the 2005 MPR, in order to provide more representative statewide values than the two-week snapshot of GMMs used for the 2004 MPR. D.05-12-042 conditionally adopt CalWEA's proposal and directed staff to finalize the specific method for determining GMM values. Staff submitted a data request to the CAISO for the simple average GMM of all the generating resources for each hour in 2005. Using CAISO data, Staff calculated the 2005 statewide average GMM to be 98.51%.

Please refer to Appendix E for a summary of the 2005 MPR non-gas inputs.

COMMENTS

Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The 30-day comment period for the draft of this resolution was neither waived or reduced. Accordingly, this draft resolution was mailed to parties for comments, and will be placed on the Commission's agenda no earlier than 30 days from today.

Comments on this resolution shall be due no later than 20 days from the mailing of this draft resolution.

FINDINGS

1. The 2005 MPRs were calculated and released consistent with prior Commission decisions.

2. Party comments on the 2005 MPR will guide future MPR calculations.

3. The 2005 MPR values for baseload proxy plants have been finalized for use in the 2005 Renewables Portfolio Standard (RPS) solicitations.

THEREFORE IT IS ORDERED THAT:

1. The 2005 MPRs in Appendix A are approved for use in the 2005 RPS solicitations.

2. This Resolution is effective today.

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on April 13, 2005; the following Commissioners voting favorably thereon:

APPENDIX A

Adopted 2005 Market Price Referents
At Specified Zonal Delivery Points (e.g., NP15 or SP15)
(Nominal - cents/kWh)

APPENDIX B

2005 MPR California and Henry Hub Gas Forecast (2006 - 2030)

APPENDIX C

Calculation of 2005 Installed Capital Costs

Contra Costa 8

Background:

On June 17, 2005, PG&E filed an application with the Commission for final approval to complete Contra Costa Unit 8 (CC8). Approval would transfer CC8 from Mirant to PG&E. The total cost to finish the project is approximately $310 million (PG&E A.05-06-029, Prepared Testimony and Appendices, Executive Summary, p.ES1). "CC8 is a partially constructed, gas-fired 530 MW 2x1 combined cycle power plant located on Mirant's existing multi-unit Contra Costa site near Antioch, California" (Id., p.1-2).

If the sale of CC8 is not completed, CC8 will remain with Mirant. At that point, Mirant will still owe PG&E $70 million, per "the settlement agreement with Mirant resolving overcharges and market manipulation claims from the sale of electricity by Mirant's California operations" (PG&E News Release, January 14, 2005, http://www.pge.com/news/news_releases/q1_2005/050114.html).

Calculation:

According to CalWEA33, the $70 million figure reflects the existing value of CC8, as described here:

Given this, the total value of CC8 would be $70 million plus $310 million, or $400 million in 2008$. Adjusting to 2006$ at 1.3% per year, the figure would be $390 million or $736/kW, which includes a $20 million adjustment for dry cooling.

Regarding the $20 million dry cooling adjustment, Staff relied on CEERT's April 1, 2003 R.01-10-024 testimony (pg.II-3):

Cosumnes (SMUD)

Background:

The Cosumnes Combined-Cycle Gas Turbine (CCGT) Project has two phases. SMUD is currently building the first 500 MW plant (Phase 1) and then it will determine by 2006 if it will build the second 500 MW plant (Phase 2) or defer construction. The plant is being built at a rural site in Sacramento County about 25 miles southeast of Sacramento.

The plant is located on a 30-acre site about a half-mile south of the now closed Rancho Seco Plant. This location allows the reuse of existing water systems, switchyards, and transmission lines that are already in place. The location of the plant site, within 2,480-acres of SMUD property, will help to reduce costs and make the best use of existing SMUD customer resources.37

Calculation:

The Cosumnes Project Revenue Bonds Series 2006 document38 shows a Total Construction Cost of $435 million at pages 4, 19, A-23, and A-24.  However, on page 4, it is noted that the Total Construction Cost does not include interconnection facilities (water, gas, electric).  Consequently, Staff added interconnection costs39, which were estimated at 5% of $435 million, and a $20 million adjustment for dry cooling.

Mountainview

Background:

In D.03-12-059, the Commission authorized Southern California Edison Company (Edison) to acquire Mountainview Power Company, LLC (MVL) as a wholly-owned subsidiary of Edison and to enter into a power purchase agreement (PPA) with MVL for the purchase of electricity from Mountainview Power Project (Mountainview), a 1,054 MW combined-cycle power plant. This project could, understandably, provide very relevant data for use in our MPR-proxy power plant calculation, however, the Commission determined that Mountainview "purchase price reflects capital costs significantly below that of any comparable new facility and is substantially below market price, it is not relevant to and cannot be adopted as the market price referent used in any solicitation conducted pursuant to the California Renewable Portfolio Standard (RPS) Program established by Senate Bill (SB) 1078" (D.03-12-059, Conclusion of Law 16). The applicable language from D.03-12-05940 reads:

Given this determination, it is possible to examine Mountainview costs, especially non-capital costs, in relation to other data points over the range of relevant cost categories. Having said that, in its August 5, 2005 MPR comments, CalWEA suggested that Mountainview could be utilized as a valid data point, if it were escalated to a market level:

Staff sees no reason for CalWEA's extra 5% and opts to escalate the total plant in-service cost for Mountainview of $703.2 by 20% to $844 million and make a $20 million adjustment for dry cooling.

Palomar

On June 9, 2004, the Commission issued D.04-06-011, which approved a Turnkey Acquisition Agreement (TAA) between SDG&E and Palomar Energy, LLC (Palomar Energy) (a subsidiary of Sempra Generation), dated January 29, 2004. Palomar is a 500 MW (base load)/555 MW (peaking load) combined cycle natural gas-fired generation plant located in Escondido, California. SDG&E will assume care, custody and control and risk of loss under the TAA upon closing, which SDG&E presently expects will occur on or about

In their 2005 MPR comments, several parties recommended that that the Commission use Palomar costs to derive the 2005 MPR installed capital costs. CalWEA proposed the most detailed proposal but it incorrectly calculated its proposed total cost per kW ($1,017/kW)41.

Staff contacted Crossborder Energy and learned that the $1,017/kW estimate was derived from values shown on Attachment A to the CalWEA Brief, "Palomar Plant Information." On Attachment A in the Annual Average column, Lines 3 and 11 were added together, and the resulting sum was divided by 500 MW: [$467.3251 million + $41.0398 million = $508.36 million] ÷ 500 MW = $1,017/kW.

There are two errors in this calculation. The $467 million figure should be $484.343 million, and the $41 million figure should not be included. First, CalWEA states that both figures on Lines 3 and 11 (CCC Brief, Attachment A) were taken from the Direct Testimony of Mike Calabrese, SDG&E, November 1, 2004, in the Palomar Application, A.04-11-003, specifically, Attachment A & B of the Calabrese Testimony. Upon reviewing the actual Direct Testimony of Mike Calabrese, it is clear that the $467 million figure used by CalWEA is an average of a mid-2006 figure and an end-of-year 2007 figure. This is problematic because nominal dollar amounts from different years are combined. In addition, the $467 million figure is reduced by accumulated depreciation and accumulated deferred taxes, both reductions from the initial balance figure. Instead, it is the initial balance figure of $484.343 million that should be used to represent the total cost of the Palomar project, given that it is the amount that would be put into rate base. 42

Second, CalWEA's addition of $41 million to the $467 million figure is in error because an annual Rate of Return (ROR) on rate base figure cannot be added to a total rate base amount to represent a total cost or purchase price. The $41 million figure is a year-specific cost paid by ratepayers as a payment for the Palomar asset that is in rate base.

Thus, the total cost for Palomar can be fairly represented by (1) the Initial Balance figure of $484.343 million as shown in the Calabrese Testimony, Attachment B; and (2) the addition of $20 million for a dry cooling system.  This results in a total cost of $504 million or $1,009/kW.  The $74 million shown on Line 9 of the Energy Division spreadsheet for Palomar is merely the difference between the $504 million and the overnight base purchase price of $410 (Calabrese Testimony, Attachment B).  The $74 million includes base purchase price adjustments, other adjustments, general plant, materials and supplies, and working cash (Id.)

Appendix D

2005 MPR Gas Forecast Inputs

1/ The Henry Hub forecasts are inputs for the MPR - Henry Hub forecast - there are no specific baseload values.

2/ Due to contractual obligations requiring the CPUC to keep the forecast confidential, staff can not reveal which of the three firms the forecast was purchased from.

Appendix E

2005 MPR Non-Gas Inputs

March 14, 2006 RESOLUTION E-3980

TO: PARTIES TO R.04-04-026:

Enclosed is draft Resolution Number E-3980 of the Energy Division. It will be on the agenda for the April 13, 2006 Commission meeting, which is held at least 30 days after the date

of this letter. The Commission may then vote on this Resolution or it may postpone a

vote until later.

When the Commission votes on a draft Resolution, it may adopt all or part of it as written, amend, modify or set it aside and prepare a different Resolution. Only when the Commission acts does the Resolution become binding on the parties.

Parties may submit comments on the draft Resolution.

An original and two copies of the comments, with a certificate of service, should be submitted to:

Jerry Royer

Energy Division

California Public Utilities Commission

505 Van Ness Avenue

San Francisco, CA 94102

jjr@cpuc.ca.gov

A copy of the comments should be submitted to:

Paul Douglas

Energy Division

California Public Utilities Commission

505 Van Ness Avenue

San Francisco, CA 94102

Fax: 415-703-2200

psd@cpuc.ca.gov

Any comments on the draft Resolution must be received by the Energy Division by March 30, 2006. Those submitting comments must serve a copy of their comments on 1) the entire service list attached to the draft Resolution, 2) all Commissioners, and 3) the Director of the Energy Division, on the same date that the comments are submitted to the Energy Division.

Comments shall be limited to five pages in length plus a subject index listing the recommended changes to the draft Resolution, a table of authorities and an appendix setting forth the proposed findings and ordering paragraphs.

Comments shall focus on factual, legal or technical errors in the proposed draft Resolution. Comments that merely reargue positions taken in the advice letter or protests will be accorded no weight and are not to be submitted.

Replies to comments on the draft resolution may be filed (i.e., received by the Energy Division) on April 6, 2006, five business days after comments are filed, and shall be limited to identifying misrepresentations of law or fact contained in the comments of other parties. Replies shall not exceed five pages in length, and shall be filed and served as set forth above for comments.

Late submitted comments or replies will not be considered.

Judith Ikle

Program Manager

Energy Division

Enclosure: Certificate of Service

CERTIFICATE OF SERVICE

I certify that I have by mail this day served a true copy of Draft Resolution E-3980 on all parties in these filings or their attorneys as shown on the attached list.

Dated March 14, 2006 at San Francisco, California.

Honesto Gatchalian

NOTICE

Parties should notify the Energy Division, Public Utilities

Commission, 505 Van Ness Avenue, Room 4002

San Francisco, CA 94102, of any change of address to

insure that they continue to receive documents. You

must indicate the Resolution number on the service list

on which your name appears.

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1 Modified by D.06-01-029

2 An act to add Sections 387, 390.1, and 399.25 to, and to add Article 16 (Sections 399.11 - 399.16) to Chapter 2.3 of Part 1 of Division 1 of, the Public Utilities Code, relating to renewable energy.

3 D.04-06-015, p.29-30

4 D.06-01-029 (OP #5, pg. 3)

5 D.04-06-015 (Footnote 21, p.30)

6 Per 12/20/05 email to CPUC Executive Director, PG&E issued its 2005 renewables solicitation on August 4, 2005 and closed it on September 15, 2005.

7 Per 3/14/06 email to CPUC Executive Director, SCE issued its renewables solicitation on September 2, 2005 and closed it on November 16, 2005.

8 Per 3/13/06 email to CPUC Executive Director, SDG&E issued its renewables solicitation on September 30, 2005 and closed it on October 18, 2005.

9 http://www.cpuc.ca.gov/WORD_PDF/FINAL_RESOLUTION/48242.DOC

10 Section 399.15(c)(3).

11 "The Henry Hub is the largest centralized point for natural gas spot and futures trading in the United States. The New York Mercantile Exchange (NYMEX) uses the Henry Hub as the point of delivery for its natural gas futures contract." ( http://www.eia.doe.gov/oiaf/analysispaper/henryhub/ ).

12 SDG&E's 2005 RPS solicitation finished (11/16/05) - after the SCE and PG&E 2005 RPS solicitations. Consequently, Staff used 11/16/05 as the last day in the 22-trading day averaging period.

13 In 2004, 3 public forecasts and 1 private forecast were used, e.g., timely forecasts produced by CERA, PIRA, Global Insight, EIA, and the CEC.

14 http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_19.xls

15 U.S. Natural Gas Markets: Relationship Between Henry Hub Spot Prices - EIA Analysis ( http://www.eia.doe.gov/oiaf/analysispaper/henryhub/index.html)

16 The CalWEA group, Green Power, PG&E, Solargenix, and TURN.

17 Documents circulated to the service list on July 11, 2005 include: 2005 MPR workshop minutes, distrib. Parties, 7/11/05; PG&E email (July 5, 2005), "Summary of MPR Cost of Capital Financing Assumptions Meeting" with 2 attachments-070505 E3 Presentation, MPR Cost of Capital and 070505 PG&E Cost of Capital Presentation.

18 While a developer could use the 20-year PPA and the strength of its balance sheet to increase the leverage in financing a particular project, the consensus of the parties is that the developer would use those characteristics to reduce the proportion of debt in project financing.

19 Energy and Environmental Economics Consultants (www.ethree.com)

20 http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3574g.pdf

21 See GE Tech. Notice - 101HA1567

22 See the CEC's Final Certification Decision for the Sutter Power Project, Docket No.97-AFC-2, at 269

23 http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger4200.pdf

24 The Energy Commission's cost of generation report is produced roughly biannually. The August 2003 Comparative Cost of California Central Station Electricity Generation Technologies report, www.energy.ca.gov/reports/2003-08-08_100-03-001.PDF, is the most recent. This report was prepared in support of the Energy Commission's 2003 Integrated Energy Policy Report (IEPR) Subsidiary Volume: Electricity and Natural Gas Assessment Report (www.energy.ca.gov/2003_energypolicy/index.html).

The Energy Commission does not plan to adopt its new cost of generation report in time for the 2005 MPR calculation. Analysis relevant to the 2005 MPR may, however, be available at a staff level. D.05-12-042 directs staff to confer with Energy Commission staff to determine what information and analysis related to the cost of generation may be available for use in the 2005 MPR.

25 http://www.energy.ca.gov/sitingcases/all_projects.html

26 CCC/CalWEA has quoted Mr. Wharton's table at page 12 of its opening brief.

27 http://www.eia.doe.gov/oiaf/archive/aeo05/assumption/pdf/0554(2005).pdf

28 Nominal dollars are economic units measured in terms of purchasing power of the date in question. A nominal value reflects the effects of general price inflation. Real or constant dollar values, by contrast, are economic units measured in terms of constant purchasing power. A real value is not affected by general price inflation. Real values can be estimated by deflating nominal values with a general price index, such as the implicit deflator for Gross Domestic Product or the Consumer Price Index. (www.nps.navy.mil/drmi/definition.htm.)

29 "Procurement and administrative costs associated with long-term contracts entered into by an electrical corporation for eligible renewable energy resources pursuant to this article, at or below the market price determined by the commission pursuant to subdivision (c) of Section 399.15, shall be deemed reasonable per se, and shall be recoverable in rates." (Section 399.14(f).)

30 CalWEA group, ORA, PG&E, and SDG&E.

31 Cite resolution 3942, which adopted the 2004 MPR

32 Installed capital costs were escalated using the US Army Corp of Engineers Escalation Index (CWBS Feature Code 07 - Updated Sept 30, 2005). Insurance, FOM, and VOM were escalated using the EIA 2006 GDP Chain-Type Price Index.

33 2005 MPR reply comments (pg. 9)

34 See A. 05-06-029, Chapter 2 of PG&E's Prepared Testimony, at 2-3.

35 "Final Staff Assessment - Part 3, Morro Bay Power Plant Project, Application for Certification (00-AFC-12)," April 2002, at p. 30.

36 "Supplemental Testimony to the La Paloma Generating Project (98-AFC-2) Final Staff Assessment," California Energy Commission Staff, April 20, 1999, at p. 2.

37 http://www.smud.org/cpp/project.htm

38 SMUD Bond Series document available online at http://www.munios.com/re.asp?ID=%9D%9Dw%81br%8Bi%85%95%87%81%BE%B7%99%93%A5%8F%C3%9A%97%97%87ik%8B%82 or type "Cosumnes" or "Sacramento" in the search box located in the upper left corner of the www.munios.com homepage. Users may have to register with the website, but documents can be downloaded at no cost.

39 In its 2003 Testimony, CEERT described these costs as "interconnection to the electric grid, interconnection to the local distribution company's gas system or an interstate pipeline, water interconnections, sewage interconnections, and other so-called "linears" (CEERT, R.01-10-024, RPS Phase, April 1, 2003, p.II-10).

40 D.03-12-059, www.cpuc.ca.gov/Published/Final_decision/32841.htm

41 CalWEA Brief, Table 1, pp.5-6, and p.11

42 Source for the $410 and $484 million figures: Direct Testimony of Michael Calabrese with Attachments A-C, SDG&E, November 1, 2004, Attachment B, Sheet 1 of 1.

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