To support the economic and operational characterization of the operational and emission impacts of the proposed divestiture, the proprietary computer models SERASYMÔ and the Surplus Energy Resource Assessment Model (SERAM IIÔ )(1) were used to simulate the future operations of the California electric system and its interactions with the rest of the Western Systems Coordinating Council(2) after restructuring with and without the occurrence of divestiture of the fossil fired power plants as proposed by the San Diego Gas And Electric Company (SDG&E).

This attachment presents the case-specific sets of assumptions and modeling approaches on which the modeling analyses are predicated. In reading these sets of assumptions, the present system configuration with the ISO controlling the system should be assumed, with the listings below serving to call out especially significant continuations or interpretations of the status quo, indicate key assumed changes from present conditions, and/or delineate approaches and modifications to the modeling as appropriate for the scenarios under study.

A myriad of assumptions and modeling methodologies go into every model forecast of electric system operations. For the 1999 Baseline case, the same set of methods and assumptions were used, except as described below, as those employed in the baseline forecast reported in the Initial Study/Mitigated Negative Declaration for the Edison Auction and PG&E’s first power plant auction in 1997 (Phase 1).(3) The assumptions from the first set of sales of particular importance to the proposed SDG&E sale include the following:

· Units continue to be bid into the ISO at minimum incremental cost and are dispatched per ISO/PX determination of minimum cost operations consistent with maintenance of system reliability.

· The ISO continues to hold agreements with its current list of "reliability must-run" (RMR) plants throughout the state, including all SDG&E plants proposed for divestiture, in the interest of having generation, and other ancillary services such as voltage support, from units at these plants available to maintain the reliable operation of the state electric system.

· The ISO operated system is assumed to include all of the interconnected northern California Municipal Utilities and the Los Angeles Department of Water and Power.

· The state’s (and the WSCC region’s) transmission systems see no major changes or upgrades other than those already approved and under construction.

· Average water conditions and resulting hydroelectric generation both in California and in the Pacific Northwest were assumed in all future years.

· California statewide electricity peak demand and annual sendout were updated to reflect the latest California Energy Commission (CEC) forecast.(4) Hourly load shapes for California utilities were updated to reflect the latest five years of Federal Energy Regulatory Commission (FERC) Form 715 data scaled to the CEC peak forecast.

· The new regional natural gas price forecasts just adopted by the CEC were employed, along with the corresponding updated inflation series forecast.(5) Special pricing adjustments were made for price of natural gas to SDG&E’s generators to reflect final adjustments for the competitive transition charges on termination of interstate gas contracts into southern California. Low sulfur fuel oil price forecasts were adjusted relative to the natural gas price forecasts to be either "cheap" or "dear" depending upon the context of the scenario.

· Selected operating characteristics of the San Diego Gas & Electric and the PG&E fossil-fueled power plants proposed for divestiture, were updated to reflect current knowledge gained during visits to those plants.

· Heat rates and other generation characteristics were updated for all fossil plants pursuant to amended Reliability Must-Run Agreement (RMRA) schedules between the California Investor Owned Utilities (IOUs) and the ISO.(6)

· SDG&E’s simultaneous import limit (SIL) from transmission to the north initiating at the San Onofre Nuclear Generating Station (SONGS) and from the east over the 500 kV Southwest Powerlink from Imperial County was assumed to be increased from 1,900 MW to 2,450 MW before 1999 thereby requiring less indigenous generation to serve SDG&E ‘s growing service area loads.

· Limitations to available natural gas for the fossil fueled plants due to gas pipeline transportation limitations are recognized and enforced on an average daily basis for each month. If all gas supplies are consumed during a given day then the individual boiler (i.e., steamer) units are modeled as being permitted to burn low sulfur fuel oil if needed for economics or to ensure electric system reliability.

· The ISO determined indigenous unit commitment rules as a function of peak daily load within the SDG&E service area as finalized in July 1998 are assumed to be followed in 1999 et seq.(7)

· Seventy megawatts of baseload generation from Edison’s El Segundo plant were dispatched to satisfy an adjacent refinery’s firm load.

· The special Mandalay natural gas supply contract between Edison and Southern California Gas Company was assumed to lapse, resulting in the Mandalay steam units receiving all natural gas at the same price as other Los Angeles Basin units.

· Pittsburg Power Plant Units 1 and 2 are operated to observe 115-kV voltage support requirements in PG&E’s Delta Area during the summer peak period.

· Consistent with PG&E continued ownership of fossil plants, the BAAQMD "bubble" regulation of NOx emissions and future downward ratcheting of NOx emission limits under BAAQMD Regulation 9, Rule 11, and other current in-state air quality permit restrictions, continue to apply.

· New default emission rates for carbon monoxide and condensable and filterable particulate matter less than 10 microns in diameter from natural gas fired boilers and combustion turbines are incorporated.(8), (9)

· A combination of Monte Carlo (MC) and probabilistic (i.e., cumulance) solution methods were employed in SERASYMÔ to provide optimal results.(10) MC solutions with attendant long computer time simulations were used to more accurately predict secondary fuel burn and combustion turbine usage in San Diego while more expedient probabilistic simulations were used for other studies and for initial calculations.

· The nomogram describing the SIL for San Diego as a function of imports from Baja California was implemented in the model to insure precise limitations to imports and better modeling of indigenous generation requirements.

· The limited fuel usage modeling algorithm in SERASYMÔ was further refined to permit precise modeling of the simultaneous usage of a common pool of limited natural gas for all the gas fired utility electric generation in San Diego. A shadow pricing approach was employed that optimized lowest cost generation from all the units prior to considering use of the secondary fuel (i.e., fuel oil) which was assumed to be available in unlimited quantities.

· The Bay Area Reliability Requirements (BARR) for unit commitment were installed and observed in the modeling pursuant to the assumed adoption and enforcement of these operational requirements by the ISO.

· The operations of the Delta plants (Pittsburg and Contra Costa Power Plants) were refined to more accurately reflect how PG&E operates the individual units to satisfy the existing water quality permit (NPDES) and expected further endangered anadromous fish protection requirements for the period from February through mid-July period.

· Transmission modeling representations among utility members of the ISO were refined and enforcement of line rating limits enhanced.

Air emissions for each of five pollutants are reported both in pounds per MWh and pounds per million Btu. For fossil-fueled plants, emissions of nitrogen oxides (NOx), sulfur oxides (SOx), carbon monoxide (CO), respirable particulate matter (PM-10) and reactive organic gases (ROG) are reported; for example, Encina 5 is shown with total 1999 NOx emissions of 200 tons (51 pounds per billion BTUs) including emissions from the nearly negligible oil burn of 1 GWh. Similar information is provided for the four other pollutants for this unit and similar information is shown for the other SDG&E fossil steamers as well. The same type of information is provided for the combustion turbines except that there is no secondary fuel burn permitted. As can be seen on Table D.1, three of the CTs (South Bay, Division and North Island 1) only burn petroleum. Since SOx is strictly a fuel-based pollutant, it is clear from looking at the emission rates that even the quite modest secondary oil burn is the major source of SOx for the steamers. The petroleum burning CTs also have higher SOx emission rates but they are all quite modest when compared to the sulfur emission from low sulfur, residual oil.

· It is assumed that were SDG&E to continue ownership of the fossil plants, it would continue with its recently updated plan for installation of emission control devices on the steamers in order to satisfy the annual 650 ton NOx ceiling currently scheduled to be in effect in San Diego prior to 2005. These further NOx control enhancements consist of: installation of SCRs in South Bay units 2 and 3, installation of selective, non-catalytic reduction control units on Encina Units 1 through 3, and installation of low NOx burners in Encina Units 4 and 5 to supplement the existing flue gas recirculation systems currently in place on those units.

· If the SDG&E plants are sold then it is assumed that the new owners would have to comply with the current requirements that after two years of ownership all boiler units would have to comply with more stringent NOx emission rate requirements consisting of 0.15 lb. of NOx/MWh and 0.40 lb./MWh for natural gas firing and residual fuel oil firing respectively. Further, upon sale it is also assumed that the new owners would not be able to use oil as readily in its boilers and that the use of oil would be limited to circumstances of force majeure that exhausted all available natural gas supplies.

· To meet load and reliability requirements in the face of local load growth, native power generation in San Francisco is supplemented by the construction of a 480-MW natural gas-fired resource patterned after the CPUC’s "Identified Deferrable Resource" (IDR) with selective catalytic reduction,(11) thereby continuing to satisfy the SFOC while obeying emission limits.

· Pittsburg Units 3 and 4 are retired consistent with an emission control plan evaluated by PG&E and with an emission control case evaluated in PG&E’s PEA for this proposed divestiture.(12) Units 1 and 2, slated for shutdown under the same plan, were retained to provide needed local system support including voltage support via their connection to the local 115-kV transmission system.(13)

· All postulated emission control improvements listed in Appendix B, Table B-2 of PG&E’s Fossil Plant PEA were incorporated into modeling, as well as the retirement of Pittsburg 3 and 4;(14) however, Pittsburg 1 and 2 were assumed retained for voltage support, with selective catalytic reduction (SCR) added to Pittsburg 2 to permit observance of the Bay Area air quality bubble standards in 2005.

The analytical maximum generation cases are intended to study the potential impacts of selling the plants to private parties with incentives greater than those of SDG&E to maximize generation sales from the plants they own.(15) Reasons a new owner might have incentive to run its units more than SDG&E are comprehensively discussed in Attachment C.

In order to investigate these potential effects, both the 1999 Baseline case and 2005 configuration of the electric system were used as starting points for a series of three sensitivity scenarios to test the environmental impacts of running these plants at their maximum credible levels of generation consistent with the market into which they sell. This market features some unavoidable limits that absolutely preclude all of these plants from simultaneously running full out. These constraints include the availability of the individual units; electric transmission limits; gas pipeline and other gas transportation limits that restrict total gas that may be made available to the plants; limited hourly demand net of ISO obligated must-run and must-take generation; existing take-or-pay contracts with out-of-state utilities; and competition from negligible or very low variable cost of generation sources including California hydro, lower cost coal generation and imports.

To implement these scenarios we chose to reduce their fuel costs in order to preserve relative economic dispatch order between the units. In the "analytical maximum" cases for the fossil plants, the natural gas prices seen by the natural gas-fired boiler units were replaced with the cheapest natural gas supply utilized in the Baseline case modeling, that of the plants with the lowest priced gas supply in California (the Coolwater plant in southern California), reduced by a further twenty-five percent and provided in quantities possible considering the limitations and higher priority customers for gas supplies imported into San Diego County.

This "analytical maximum" concept was also applied to the gas fired combustion turbines to be divested as well as with the resource addition in a 2005 scenario. The gas fired CTs were included in the Analytical Maximum even though it was anticipated that they would remain subject to Must-Run agreements with the ISO and would be committed only by the ISO. By offering cheaper fuel prices the new Owner would encourage the ISO to commit these units for reliability/ancillary purposes more frequently than other CTs in the state.

· The new plant to be constructed to replace South Bay (i.e., referred to as IDR in the tables of results, or Otay Mesa) would have four 240 combined cycle units with an additional 100 MW CT for a total of 1,060 MW of generation. These efficient units would be equipped with SCRs that would limit emissions to no more than 0.15 lb. of NOx per MW hour of generation.

· The new plant would have its own, dedicated firm gas supply and all of the gas that would otherwise have been available to both the South Bay and Encina plants would now be available to support Encina generation.(16)

· The new CT would be assumed to have a typical peaker-unit Must-Run agreement and would be used for reliability purposes solely.

· The new generation would eliminate the need for unit commitment of any units at the Encina plant with those responsibilities handed over to the newer, more efficient generation.

· The recommended mitigation measures for air emissions would still be implemented consisting of the need for SCRs and the restriction of use of fuel oil for generation. Relatively little fuel oil would be used under any circumstances since this scenario assumes much more gas is available to fire native generation.

As compared to the 1999 Baseline case, Variant 2 includes much greater generation and a bit more use of fuel oil by the steamers and the new plant. The new CT is used about twice as frequently as the existing CTs but even at that is used about a six percent capacity factor, well within the normal range of stand-alone CTs. Total NOx emissions from generation is less in this scenario than in the 1999 Baseline case while other emissions increase somewhat.

· Overall emissions throughout the WSCC (including California) attributable to meeting California electric load decline substantially for NOx, SOx, and PM-10 and increase modestly for CO if the SDG&E plants to be divested are assumed to run at their full analytical maximum outputs consistent with available gas supplies.

· The greatest potential increase in NOx emissions due to divestiture, represented by the difference between baseline conditions and analytical maximum operations, declines very rapidly between 1999 and 2005 assuming future installation of emission control equipment on the plants consistent with current regulation.

· If the NOx cap were transferred to the new owners for the two year period during which the stricter emission rate requirements were being retrofitted onto the steamers then the emissions rates for NOx from the plants would likely decline more than if SDG&E continued to own the plants.