||APPROACH TO DEFINING THE SCOPE OF ANALYSIS
The project proponent (SCE) proposes to value its 56% share in the MGS through an auction. SCE has identified the construction of 500 feet of fencing (to separate the MGS from the switching yard) as the only physical improvement that may result from the sale.
Research on other divested power plants( MRW & Associates 1999, see Appendix A) indicates that new owners of coal-fired power plants search for methods to boost capacity, while keeping within the limits of environmental permits and regulations (see Appendix A). Given that the new owners tended to increase energy production and given the requirement that reasonably foreseeable consequences of the initial project must be explored, this Initial Study includes a review of possible connected actions. This section identifies a series of possible connected actions, or scenarios, and evaluates each one to determine if the scenario is reasonably foreseeable and to determine if the possible effects should be analyzed in the remainder of the Initial Study.
This section describes the proposed action, the approach to defining related actions, and potential actions that must be addressed in this Initial Study. Section 3.2 describes the proposed project. The subsequent sections describe the possible connected actions that may result from the sale of the SCE share of the MGS and provides a conclusion as to whether the actions are reasonably foreseeable and therefore subject to CEQA review. The reasonably foreseeable effects are then analyzed in Section 4 of this Initial Study.
SALE OF THE MGS
SCE is a California Public Utility and the 56% share in the MGS controlled by SCE is subject to CPUC jurisdiction. The sale of the MGS by SCE would transfer the ownership of 56% of the MGS to a new owner.
SCE has proposed that a fence may be constructed to separate the switching yard from the generating facilities at the MGS. The sale of the MGS would result in a direct physical change to the environment if the 500-foot fence is constructed. See Figure 2-2, which illustrates the location of the proposed fence.
RELATIONSHIP TO PROJECT DESCRIPTION
The proposed actions are a part of the project described in the Project Description (Section 2 of this document). The environmental impact of the sale and the fence are considered in the Initial Study (Section 4).
Possible Connected Actions
BASIS FOR DEFINING CONNECTED ACTIONS
Purpose of Analysis of Connected Actions
Project descriptions under CEQA are required to account for reasonably foreseeable future phases, or other reasonably foreseeable consequences of proposed projects. A two pronged test to identify reasonably foreseeable projects requires that an EIR must include an analysis of an action if: "(1) it is a reasonably foreseeable consequence of the initial project; and (2) the future expansion or action will likely change the scope or nature of the initial project or its environmental effects." (Laurel Heights Improvement Association of San Francisco, Inc. v. Regents of the University of California, 1988).
The recent deregulation of the electric utility industry has resulted in the divestiture of a number of utility-owned generation facilities. New owners often make changes at the divested facilities (MRW & Associates 1999). The CPUC must determine whether the proposed project would cause significant environmental impacts. Potential actions of new owners must be considered to determine the potential effects of the project and to ensure reasonably foreseeable environmental effects of the proposed project are identified and evaluated.
Review of Other Divestitures
Previous divestitures were reviewed to determine if new owners would have different incentives to make changes to the plant or its operations when compared to the incumbent owner. This research indicates that a new owner would be:
Exposed to market forces of full competition
Likely to file for and receive market-based rates
Able to participate in bilateral trade or alternative wholesale trade
Able to avoid sharing of risk or incremental revenues with customers
Likely to have a different portfolio of generation and fuel assets or contracts that may affect operations.
SCE, as a regulated utility, is required before the end of the transition period (March 31, 2002) to:
Sell to the Power Exchange (PX) and buy power from the PX
Contribute to stranded cost collection revenues from the plant in excess of going-forward costs
Have capital additions subject to reasonableness review
After the end of the transition period SCE will be allowed to:
Market value the project and offset stranded costs
Continue operation of the MGS subject to operating in the public interest
Operate under performance-based regulation
Before the end of the transition period, a new owner would have access to new markets, which could change the incentive to operate the MGS. SCE is required to sell the MGS output to the PX and PX revenues in excess of operating costs are generally credited to ratepayers and could hasten the end of the rate freeze required by AB 1890. SCEs incentive to minimize costs or increase output are therefore more muted when compared to a new owner during the transition period.
The above conclusions show that new owners have incentives to operate plants differently than an existing owner, such as SCE and its co-tenants at the MGS (MRW & Associates 1999). The new owners tend to increase plant output. Case studies of the sale of coal-fired power plants indicate that new owners tend to install new equipment, particularly emission controls, and operate the power plants they acquire at a higher rate. The review of different scenarios under which the new owners would be expected to operate the MGS is therefore necessary to understand the full range of environmental effects that could occur as a result of the sale of the plant.
The following subsections describe a range of connected actions or scenarios that could occur under new ownership of the MGS, issues related to the potential connected actions, and a conclusion as to whether the scenario is foreseeable and subject to CEQA analysis. None of these scenarios have been proposed by SCE. These scenarios are reviewed to independently determine whether any reasonably foreseeable significant effects could occur as a result of the project.
Possible Connected Actions
A range of possible actions could occur if SCE sells its share of the plant. These actions may be induced by the sale; some of the induced effects could result in physical changes to the environment.
The possible connected actions that are described below include:
Continued existing operations
Increased plant output
Increased use of natural gas
Conversion of the MGS to natural gas
Construction of a new natural gas plant
Sale of the MGS and plant closure
There is a possibility that some or all of the existing owners of the MGS (LADWP, SRP, and NPC) may sell their shares in the plant at the same time that SCE sells its share .
All four of the MGS owners may decide to sell their share of the MGS together; conversely, only one or two of the remaining owners may decide to sell their share in the MGS. The sale of the remaining three ownership shares of the MGS not owned by SCE is not subject to CPUC jurisdiction because the other three owners are not utilities regulated by the CPUC.
It is expected that the sale of the entire the MGS to a new owner would give the new owner greater flexibility in decisions on how to run the MGS and how to alter plant operations. The agreement between the four MGS owners requires all four owners to agree to major changes to plant operations and equipment. The sale of 100% of the MGS would result in transfer of ownership of the entire MGS to a single owner with sole decision-making authority.
Each owner currently has an equal role in the decision-making process regarding operation at the MGS. If SCE sells its share and one or all of the other owners retain their share, the new owners would have less flexibility in making changes at the MGS. A new owners flexibility would be maximized if the entire MGS were acquired. The greatest potential for change results from sale of all four owners interest in the MGS to a new owner. If SCE is the only owner who sells its share, the new plant owner would be restricted because the remaining existing owners may not agree to changes. The greatest level of change in the environment would be expected to occur if a new owner buys all four shares of the MGS. Thus, to be conservative, this Initial Study assumes that all four owners of the MGS would sell their shares in the MGS.
CONTINUED COAL OPERATIONS
Continued Existing Operations
Description. In this scenario, the operations at the MGS are essentially the same as those currently occurring.
Evaluation. The new owner could continue to curtail MGS generation (in the range of 1 to 3% of capacity) for economic reasons. Under this scenario, the MGS can continue to operate within the confines of existing permit requirements.
This scenario is viewed as reasonably foreseeable if SCE only sells its 56% share and the three existing owners prefer to continue existing operations. Environmental impacts occurring under this scenario are identical to the existing conditions; therefore, no new environmental impacts are expected to occur under this scenario.
Description. Under an increased operations scenario, it is assumed the new owner would maximize plant output to maximize profit. In this scenario the new owner is expected to increase operations within the physical constraints of existing equipment and within the limits of existing permits. The increased operations could result from revised maintenance practices or replacement of old equipment.
Evaluation. Prior independent buyers of divested power plants that have only a single power plant in a region have usually increased operations at the generating facilities they have purchased (MRW & Associates 1999). The addition of air pollution control equipment is a common action of new owners (see discussion regarding adding additional pollution controls below).
The MGS output could be increased because the plant is not currently running at maximum output. The MGS capacity factor (i.e., a measure of the actual generation of a facility compared to design generation) has been reduced for economic reasons by 2.75% in 1998 and 1.03% in the first 11 months of 1999. Table 3-1 illustrates the capacity factor at the MGS since 1990. The capacity factor has varied from a low of 64.3% in 1990 to a high of 76.5% in 1992. The MGS output has been curtailed as a result of periodic exceedance of the air opacity limits specified in the stations air emission permits.
At the MGS, air pollution permit requirements are the major reason that generation is curtailed. Coal is the primary fuel used at the MGS. Natural gas is used for start-up, to dry the coal slurry, and to ensure the flue gas is hot enough during start-up to allow pollution controls to operate efficiently.
According to a study reported in Electric Light & Power, October 1999, the capacity factor of the top 50 USA coal fired plants averaged 68.23% and varied from a low of 51.45% to a high of 89.72%. This indicates that the MGS is operating well within the range of other well-run coal fired power plants in the USA. The fact that the MGS does not now have a scrubber and a bag house to control air emissions and that opacity is a key constraint to operating the plant more intensely indicates that the MGS is running close to its maximum output given physical and permit constraints. Therefore, a new owner of the MGS may be able to increase output under these circumstances by changing maintenance practices and decreasing economic curtailment (economic curtailment is reduction in generation due to economic factors) but only by a relatively small margin.
Table 3-1: Annual Performance (1990-1998) (in percent)
SOURCE: Mohave Generating Station Technical Review (SCE 1998)
Estimating the amount of increase in output due to a change in ownership of the MGS is difficult because there is a complicated relationship between opacity of the air emissions and the amount of energy generation. Using a worst-case estimate of curtailment of 2.9% for economic reasons and the range of plant capacity factor indicated in the Electric Light and Power article cited above, a rough estimate is possible. No coal-fired plant is currently operating above a 90% capacity factor for extended periods of time. The MGS has recently been running at a capacity factor of approximately 70%. Since 1990 the highest annual capacity factor at the MGS has been 76.52% (1992). Compared to the most efficient coal fired plant, the MGS could theoretically increase output by up to 20% from the 1998/99 capacity factor. With varying opacity constraints (40% and then 30% opacity), the MGS has run historically at a capacity factor that is up to about 6% more than the current capacity factor of approximately 70%.
The actual amount of the potential increase in capacity factor is likely to be considerably below 20% for several reasons. The MGS is a relatively old plant that requires more maintenance and will have more breakdowns requiring a curtailment of generation while the maintenance is performed. The MGS has additional constraints on generation. Air permits currently limit opacity. Generation is reduced at the MGS on a daily basis due to reaching the opacity constraint. In past years generation at the MGS was curtailed mainly because of the limitations imposed by the opacity constraint.
The MGS also has a limited water supply that can limit energy generation, especially during warm weather. Given the historical capacity factor, the age of the MGS, and the constraints on air emissions and water supply, it is unlikely that the MGS could increase output within existing equipment and permit constraints more than 10% above 1998/1999 levels.
The new owners of the MGS would not have precisely the same operating experience, qualifications, financing, or corporate philosophy as SCE. SCE is required to continue to operate the MGS for two years after the sale of the plant. A new company could change maintenance practices (e.g., replace several short duration planned outages with one long one or reduce the total duration of planned outages). This change in operations would be subject to the consent of the remaining three owners of the MGS. If all of the owners agree to sell their shares in the MGS, this constraint to modifying operations at the MGS would be eliminated. The flexibility of new owners would be maximized if all four owners of the MGS elect to sell their share.
New owners of the MGS could increase output at the MGS by changing maintenance practices. This could involve reducing the frequency or duration of maintenance outages at the MGS. Spare part inventories could be increased to reduce the duration of outages. By ensuring that spare parts are available on the site instead of waiting for supplies to arrive, outage time would be reduced and operation time would be increased (SCE has indicated that the MGS does not always have the parts needed on-site). Maintenance schedules could be revised to defer maintenance and increase operation time. Increased operation time allows for increased plant output.
The MGS could increase output by changing or modifying equipment that is currently at the MGS. For example more centrifuges or modified centrifuges could be used to further dry the coal slurry and create a more efficient burning fuel.
An increase of 10% in production by the MGS is regarded as reasonably foreseeable. A new owner could increase generation 10% (provided this occurs within air permit constraints) without any discretionary approval, if the new owner could find a market for this additional energy output. A new owner would be able to identify a new market for the additional energy more easily than SCE because the new owner would not be required to sell to the PX in the transition period.
The environmental impacts of increasing generation by 10% will be analyzed in the Initial Study because this is identified as reasonably foreseeable.
CONNECTED ACTIONS USING NATURAL GAS
Increased Use of Gas
Description. This scenario involves the increased use of natural gas at the MGS by a new owner. Gas use would be increased above 15% and could completely replace coal as a fuel for the MGS. This scenario would involve replacement of equipment at the MGS to allow for the efficient use of gas as a fuel. The MGS would continue to operate under existing permits.
Evaluation. An existing pipeline supplies natural gas to the MGS for start-up of the coal fuel system. Natural gas burns cleaner than coal and increased gas use could reduce emissions and allow more generation of power. It is necessary to evaluate whether it is likely for a new owner to use more natural gas for fuel to facilitate increased generation while staying within current permit limits for air emissions. Numerous factors, including boiler design, existing gas pipeline capacity, and coal fuel moisture, all constrain the use of natural gas.
Factors Constraining the Use of Gas. The boilers at the MGS are each designed to operate using coal fuel and are considerably larger (double the size) than they would be if designed to operate on natural gas. The arrangement of boiler tubes (radiant surface versus convection surface) in the MGS boilers is also significantly different than it would be for a gas-fired boiler.
The boilers at MGS are each designed to operate using coal fuel to produce 790 MW (net) from approximately 5.5 million pounds of steam per hour at 3,500 pounds per square inch (psi) and 1000F. As such, they are considerably larger than they would be if designed to operate on natural gas. For comparison, the boilers at SCEs Ormond Beach Generating Station are each designed to operate using natural gas fuel to produce 750 MW (net) from approximately 5.2 million pounds of steam per hour at 3,500 psi and 1000F. The volume of each of the boilers at MGS is 416,000 cubic feet, whereas the volume of each of the boilers at Ormond Beach is 208,450 cubic feet. Also, the arrangement of boiler tubes (radiant surface versus convection surface) in the MGS boilers is significantly different than it would be for a gas-fired boiler.
MGS does use some natural gas in conjunction with coal, and it is equipped with three gas burn systems in the boilers: igniters, warm up guns, and main gas nozzles. The igniters are somewhat analogous to matches: they provide the initial ignition and light the warm up guns. The warm up guns are somewhat analogous to torches and they light the coal, which is the plants main fuel. The main gas nozzles could be used for operation of the unit on gas fuel alone, without coal, and they apparently were installed as a precautionary back-up out of concern that the plants coal-slurry supply system might be subject to occasional interruption. (At the time of the plants construction the coal-slurry pipeline was a new and relatively unproven technology.) The igniters and warm up guns are used in the operation of the plant and are thus still in place and operational. The total gas capacity of the igniters and warm up guns is approximately 880 million British thermal units (MMBtu/hr) or 21,000 MMBtu/day. The main gas system is still largely in place, but is no longer operable since it has not been used in years and has been cannibalized for parts for other systems. The total gas capacity of the main gas system (if the system were operational) would be approximately 7,200 Btu/hr (172,800 MMBtu/day) which is approximately 15% less than the coal fuel capacity of 8,374 MMBtu/hr (200,976 MMBtu/day).
The only time that the main gas system was ever used was during the initial startup and operation of the units in the early 1970s. During that time, the main gas system was not used to run the plant completely on gas instead of coal, but rather as a makeshift way to provide sufficient heat to dry the coal at low load (electrical output) operation in order to allow the units to achieve full load on coal. This approach was used because the coal fuel moisture content was higher than originally anticipated. Subsequently, a modification was made to add duct burners to provide the additional heat rather than using the main gas system, and the main gas system was no longer used. Eventually, better centrifuges were installed, which reduced fuel moisture somewhat. As a result, the duct burners are now needed only during start-up, although the excess moisture continues to affect opacity compliance (see below).
At present, the gas pipeline into the MGS has the capacity to supply a firm, uninterruptible gas commitment of 18 million cubic feet per day (MMcfd) on average, equivalent to approximately 80 MW. The existing pipeline also has capacity for an additional 15 MMcfd per day of interruptible gas, equivalent to approximately 65 MW. El Paso Natural Gas Company (El Paso), the current supplier, has stated that to provide 33 MMcfd per day (145 MW) of firm, uninterruptible gas to the MGS would probably require that it upgrade approximately 6 to 10 miles of the existing 8-inch pipeline in the Bullhead City/Fort Mohave area of Arizona. The cost of this improvement could range upwards from an estimated $500,000 per mile for flat, cross-country terrain to nearly $2 million per mile when traversing city streets.
El Paso has also stated that to provide the MGS with a firm, uninterruptible gas supply of 375 MMcfd per day (approximately 1,600 MW) would require that a new 24-inch pipeline be constructed from the Topock Compressor Station in Arizona to the MGS, a distance of approximately 36 miles. This new pipeline would probably follow the existing El Paso Natural Gas/Southwest Gas 20-inch pipeline No. 2153 to the Nevada/Arizona border near Fort Mohave, Arizona, where it would cross under the Colorado River and on to the MGS.
Discussions with various gas suppliers have indicated that this quantity of gas probably is available for sale to the MGS if this pipeline were to be built. Typical impacts related to gas pipeline construction include surface disturbance in a corridor 25 to 200 feet wide. Surface disturbance for construction would temporarily affect soils, vegetation, and wildlife. Other effects include potentially lower SO2 and other air emissions and perhaps lower employment rates at the MGS and at the coal mines.
The additional fuel moisture at MGS (described above) causes several, cumulative problems with respect to maintaining compliance with the plants opacity limits. First, the moisture itself increases the mass flow rate through the boiler and, most importantly, through the electrostatic precipitators (ESPs). The moisture means more molecules--the water vapor--pass through the ESPs in a given time period, which reduces the ESPs effectiveness at removing particulates and thus tends to increase opacity. Second, more fuel is required to evaporate the moisture and to raise its temperature to the flame temperature, and this additional fuel further increases the mass flow rate. Third, the additional mass flow rate causes the heat input to be used less efficiently and thereby raises the flue gas exit temperatures at high loads above what was expected. The additional temperature results in a higher specific volume of the flue gas, which in turn increases the flue gas velocity through the ESPs still further.
Coupled with the fact that the ESPs are small compared to todays standards, these factors mean that the plant is operating to the limits of the ESPs effectiveness, and the plant often has to reduce generation to keep in compliance with the opacity limits.
In 1991-1992, SCE conducted a test at the MGS to determine if more gas fuel could be burned to increase load when opacity was limiting load. The study showed that using the 18 MMcfd per day of available gas, output could only be increased by 20 MW. The use of gas fuel further increased flue gas velocity in the ESPs, which resulted in the need to reduce coal firing by 60 MW so that the full 18 MMcfd per day of gas could be fired and still maintain the same opacity level. This phenomenon results from the additional moisture that is created when the hydrogen in the gas fuel oxidizes into water vapor in the combustion process. With natural gas fuel, there is considerably more moisture created per pound of fuel than with coal because there is more hydrogen in natural gas than in coal. Thus, there is more moisture in the flue gas which, as already explained, results in higher velocities in the ESPs and reduced ESP effectiveness.
With the higher gas velocity, the only way to reduce opacity was to reduce the particulate loading by reducing the coal input. The differential fuel cost between the price of coal and the incremental cost of gas made this mode of operation uneconomical. More gas fuel could be introduced at lower loads because the mass flow rate would be lower also. At lower load, opacity would not normally be a limiting factor. However, at lower load when opacity is not limiting, coal fuel can also be used, which is much lower in cost than gas. It is only at higher loads near 700 MW that the velocity/opacity factor becomes limiting.
Converting to Combined-cycle Units. SCE has also investigated, on a screening level, converting the MGS to combined-cycle units by replacing the boilers with combustion turbines. SCE determined that this conversion is also not economical because of the poor match in steam conditions between the Heat Recovery Steam Generators (HRSG) of a combined cycle unit and the existing MGS steam turbines. This poor match would result in the existing MGS High Pressure (HP) turbines not being used. While these turbines could be replaced, the increased use of gas under these conditions was determined by SCE to be infeasible for engineering and economic reasons.
Adding a new, separate combined cycle plant to the MGS site would present several issues that might not be immediately apparent. Under the present water contract for the plant, limited water is available to the site. Nearly all of this water is currently being used. (Upon installation of the pollution controls required by the Consent Decree, moreover, it is expected that all of the presently available water will be used.) To add a combined cycle plant to the site would require either (a) acquisition of additional water, which might not be available and would be expensive, or (b) that the new plant employ "dry" cooling. "Dry" cooling does not require cooling water to condense the steam as do conventional systems such as the one used at MGS. An important difference between the existing plant and dry cooling is that the existing turbines exhaust steam at a back pressure of 3-5 inches Hg depending on ambient temperature, and dry cooling would require the combined cycle turbines to exhaust steam at approximately 10-15 inches Hg for the same ambient temperature. The lower the back pressure the more efficient the process. Thus, a dry cooled combined cycle unit on the MGS site (hot, desert location) would not be as efficient (i.e., economical) as a similar unit with conventional cooling located where water was available, nor would it be as economical as an identical dry cooled plant sited somewhere else with more favorable (cooler) ambient temperatures.
Acquisition of additional water would also be problematic. The MGS is currently operating under an agreement with the Colorado River Commission that states that the MGS shall use coal from the Black Mesa Indian Reservation Lands to fuel the MGS. The MGS is authorized to use natural gas for up to 15% of full-load capability. The use of Colorado River water to operate the MGS is contingent upon the use of the coal from the Black Mesa lands. If the MGS uses more than 15% of its fuel from gas it would not have an adequate supply of water to create steam and cool equipment. Groundwater in the area is insufficient to supply the needs of the MGS.
Switching from Coal to 100% Gas. Although it has never been tested because the gas fuel pipeline is inadequate, it is expected that full load (790 MW per unit) cannot be achieved at MGS on gas fuel. Due to the differences in design between a boiler designed for coal and a boiler designed for natural gas, SCE determined that the flue gas exhaust temperature would be greater than the present temperature of 345F and would exceed the design limits of the back end of the boiler; i.e., the temperature limits for such equipment as ducting, seals, and the ESPs.
Although the full design load of 790 MW probably could not be achieved, SCE did conduct a screening investigation in the 1991-92 time frame for the purpose of evaluating Best Available Control Technology (BACT) as compared to the option of eliminating coal as a fuel and burning only natural gas year-round for full operation. It was determined at that time that the order-of-magnitude Net Present Value (NPV) cost of BACT was approximately $500 million. The NPV cost of replacing coal with gas was on the order of $1.2 billion, more than twice the cost of BACT. This difference is due to the differential fuel costs. Not included in this evaluation was the cost of the new gas pipeline, the cost of refurbishing the main gas systems at MGS, or the cost of any modifications to the boilers to allow more efficient usage of the gas fuel. These additional costs, while quite large in themselves (possibly in the hundreds of millions of dollars), are small when compared to the $1.2 billion differential fuel cost and would increase the differential.
More recent investigations (1998) looking at replacing coal fuel with natural gas only during the summer to replace summer megawatt hours lost due to opacity restrictions have also found that this mode of operation is not economical under current market conditions. Summer was deemed to be the most advantageous time for the replacement because the gas prices are at their lowest and the value of energy is at its highest. Even under these most beneficial conditions for gas fuel, gas fuel replacement during the summer only becomes economical when the value of the energy is several times more on a sustained basis than it has been historically.
Conclusion. New owners may have different economics and may choose to solve the engineering issues with replacing equipment. The difference in incentive would diminish after the end of the transition period. The cost of the new equipment combined with the cost of upgrade or replacement of the gas pipeline make significant increase in gas usage speculative. Use of natural gas for more than 15% of the MGS fuel supply would result in the elimination of the MGSs rights to use Colorado River water, creating a water supply problem for the MGS. There is no current basis to determine that increased use of gas is reasonably foreseeable. The environmental effects of using more gas will therefore not be analyzed in detail in this Initial Study. For these reasons the environmental analysis assumes that implementation of the project would not affect the type of fuel used at the existing MGS facility. The new owner of the plant would continue to use coal as the primary fuel and would use natural gas only for start-up.
New Natural Gas Plant
Description. New owners could choose to either retrofit the MGS with gas or construct a new gas-fired power plant to replace the MGS plant. If all four owners sell their shares in the MGS the new owner could construct a new power plant that runs on natural gas.
Evaluation. The existing natural gas pipeline to the plant could be upgraded to carry more gas (see above discussion). Existing electrical transmission service would be used. The MGS property has sufficient land to accommodate a new power plant, and electric transmission facilities exist that could be utilized by the new plant. Gas supplies are currently available subject to the transportation constraints identified above.
Construction of a new power plant would probably result in the closure of the Peabody Mines and slurry pipelines and would result in the loss of jobs. This scenario would result in lower air emissions because natural gas is cleaner burning than coal.
If this scenario were to occur, discretionary approval and environmental review would be required to construct and operate the new plant. Since the MGS would no longer have a sufficient water supply if it no longer uses coal for more than 85% of its production, this scenario is not reasonably foreseeable. The impacts of this scenario are therefore not described in this Initial Study.
Operation of the MGS with Addition of a Gas Plant
Description. A new separate combined cycle gas plant could be added to the existing power plant.
Evaluation. Adding a new, separate combined cycle gas power plant to the MGS site would also present several issues. Construction of a natural gas plant on the existing MGS property could be considered part of the MGS facility. The new gas plant would require a new water supply. Construction of a gas plant would add to the capacity of the MGS. The MGS water agreement requires the use of gas for no more than 15% of the plants fuel supply; the water is not available to the MGS if the coal contract is broken. Addition of a gas plant would increase the output of the MGS and the amount of gas used as a proportion of the total fuel use. The gas plant could increase the amount of gas used at the MGS to over 15%, and therefore potentially nullify the water agreement.
Significant improvements would be needed to both the natural gas line and the MGS to allow for generation from a separate plant at the MGS facility. Electric transmission line improvements would likely be required to accommodate a second plant on the MGS site. Construction of a new power plant would require environmental review and discretionary approval for these improvements. Opportunities for agencies and members of the public to participate would occur during the required review.
Construction of a second power plant at the MGS facility has not been proposed. It is not clear that sufficient water is available to supply a second plant. Projects in Laughlin have been abandoned during construction because of a shortage of water. The addition of a gas plant at the MGS is therefore considered not reasonably foreseeable. The impacts of this scenario are therefore not described in this Initial Study.
SALE OF PLANT AND SHUT DOWN
Description. The entire MGS would be sold to a new owner and then it would be closed down.
Evaluation. As the divested plants are sold, repowered, expanded, retired, or operated as is, the employment levels at the plants could be affected. Although AB 1890 requires sold and operating plants to be operated and maintained by SCE for two years, no mandate exists that requires the plants to continue to operate after being sold unless they are "must-run" plants. The MGS is not currently designated as a must-run plant; therefore, the MGS could be shut down after it is sold.
The shut down of the MGS is not anticipated if the MGS is sold. A new owner would have to spend considerable resources to purchase the MGS. Comparable plants sold in the USA in the last five years cost an estimated $350,000,000. The question arises as to why a company would spend several hundred million dollars just to close the MGS. The property values of the MGS site are likely not high enough to warrant closure of the plant and development of a new use on the site. A new use providing a higher return would be subject to similar water supply problems as the MGS.
Assuming that not all owners agreed to sell their share of the MGS, the new owner would need the other owners to agree to close the MGS. The new owner would have more flexibility in closing the MGS if all of the owners choose to sell their share. The closure of the MGS is identified as not reasonably foreseeable because it is not clear that all of the MGS owners will agree to sell their share of the MGS and because there appears to be no economic incentive to buy the MGS to close it. The impacts of this scenario are therefore not described in this Initial Study.
The scenarios identified as reasonably foreseeable in the above evaluations are analyzed in Chapter 4 of this document. The scenarios identified as reasonably foreseeable are:
Continued existing operations
Increased plant output by 10%