APPROACH TO ENVIRONMENTAL ANALYSIS
In 1996, the CPUC initiated and then suspended preparation of a policy-level Environmental Impact Report (EIR) to study the environmental effects of the entire electric industry restructuring process. The enactment of Assembly Bill (AB) 1890 (Stats. 1996, Ch. 854) took precedence in planning the new electric market. This rendered an EIR on restructuring unnecessary since, with the enactment of AB 1890, the policy of introducing competition into California's electric generation sector in 1998 is now law, and the implementation of laws enacted by the Legislature is exempt from CEQA.
Although divestiture of the PG&E facilities, the "project" considered in this environmental analysis, is not mandated by AB 1890, its implementation would facilitate the AB 1890 goal of a competitive market. Because of this, the CPUC's Preferred Policy divestiture by Investor Owned Utilities (IOUs), such as PG&E, remains in effect. AB 1890 does mandate that these facilities must be market-valued before January 1, 2002, which can occur through divestiture.
This Initial Study considers whether PG&E's proposed divestiture would likely lead to significant effects on the environment as a result of either (1) physical changes associated directly with the ownership transfer, or (2) distinguishable operational changes at the plants proposed for sale, that are different or greater than would occur solely due to restructuring. The types of changes that could produce environmental impacts are considered in the following bulleted items. The changes that are assumed to be reasonably foreseeable versus those that would be too speculative to consider at this time (i.e., a description of the changes being analyzed in this Initial Study) are then identified in the following section titled "Reasonably Foreseeable Project Future".
Because the California electric system will be operated in an even more integrated manner than before, with many interconnections between control areas, the above changes could have environmental effects at facilities in addition to those to be divested. For example, increasing generation at one in-state plant could decrease generation at other in-state facilities, out-of-state generation, net imports into the state, and loads on interstate transmission lines. This "re-mixing" of generation could create environmental impacts within California. However, as discussed below, to precisely predict the generation output of each power plant unit would be speculative.
REASONABLY FORESEEABLE PROJECT FUTURE
The manner in which the various factors discussed above would actually play themselves out will determine the environmental impacts of the project. The environmental analysis should be based upon the reasonably foreseeable changes that will result from divestiture, in terms of power plant operating characteristics, new construction, repowering or retirement of units, and employment levels. This section describes, based upon an initial economic and operational analysis of PG&Es proposed plan for divestiture which is discussed in further detail in Attachment C, the projected changes likely to result from divestiture compared to the changes expected to stem from restructuring alone, without divestiture. This scenario forms the basis for the environmental analysis in this Initial Study. This section also describes potential changes under divestiture (discussed above) which are not reasonably foreseeable or cannot be reliably predicted; such speculative changes do not form the basis for the environmental analysis in this Initial Study.
This environmental analysis assumes that implementation of the project would not affect the type of fuel used to fire the three power plants. The new owners of the Morro Bay and Moss Landing plants would continue to use natural gas as the primary fuel and fuel oil only as a back-up or emergency fuel. In comparison to fuel oil, natural gas is relatively inexpensive, reduces maintenance costs and is cleaner burning.
It can be reasonably foreseen that there will be a difference in how the three divested facilities will be operated by non-utility generators as opposed to how all of PG&Es facilities would be operated without divestiture in a future restructured world. It would be expected that, if PG&E did not divest, it would submit bid packages to the Power Exchange (PX) that would run the more efficient plants at high capacity levels and use the less efficient plants only when their capacity is needed. In contrast, new owners have incentives to operate their newly acquired plants in a more constant mode, particularly if they do not own any other plants in the region. Furthermore, new owners can immediately sell power directly to users in addition to the PX, unlike PG&E, which is constrained to selling only to the PX prior to market valuation of the plants. Attachment C was prepared primarily to answer the question whether new plant owners would tend to generate more electricity than would the existing utility owners in a restructured setting. The analysis in Attachment C in fact demonstrates that new owners would tend to operate at higher levels, particularly during the transition period prior to 2002, due to three factors: (1) the portfolio effect, which is the availability to utility owners of a portfolio of electricity-generating assets, (2) fuel procurement practices, and the possibility that new owners would purchase natural gas at a lower cost per unit or in a different fashion than would the existing utility owners, and (3) the ability of new owners immediately to participate in the direct access market while the utilities must initially sell all of their power through the PX.
There is, however, a great deal of uncertainty and interactive variables that make it infeasible to predict the increase in generation at any particular divested plant, or even whether generation would increase at any divested plant, as described below.
With restructuring and without divestiture of the three plants, the market value of the plants must by some means be established and approved by the CPUC no later than the end of 2001. Once market valuation occurs, the plants could be sold without CPUC approval. Thus, implementation of restructuring itself could result in plants being sold after their market value is established. PG&E would not be required to sell its plants, and it is not certain that the plants would be sold. The evidence in the record does not establish whether PG&E would retain or sell the three plants if the project were not approved. It is simply noteworthy that the plants could be sold, so that the physical and operational differences between restructuring with divestiture as currently proposed and without divestiture could, as a practical matter, be minimized or even eliminated, except in the period before market valuation of the plants.
Assuming that PG&E would continue to own the three plants in the future if its divestiture application were not approved, the exercise of any potential market power by PG&E would be monitored and regulated by the Federal Energy Regulatory Commission (FERC). It has not been determined what measures FERC would impose. While such measures might not be as effective in mitigating market power as the outright sales of the plants would be, the FERC-imposed measures could curtail to some extent PG&E's ability to employ the portfolio effect to gain market advantage, thus bringing PG&E's future operation of the three plants closer to the levels at which new owners would operate.
Since the utilities can participate in the direct access market as of 2002 (or sooner if their plants' market values are approved by the CPUC), the tendency of new owners to generate more than existing owners lessens after the transition period. Thus, impacts that may be associated with increased generation (to the extent that such generation flows from the ability to participate in the direct access market) would be temporary.
At the time of preparation of this Initial Study, the identities of the purchasers of the plants is not known. The greatest potential for increased generation at a plant would exist if the plant were bought by a separate, independent entity that does not own other generation facilities within California. If a single entity buys several plants and/or owns other generating facilities (e.g., wind power, coal and/or hydroelectric plants), or to the extent that singly-owned plants are reconstituted into larger portfolios in the future, the tendency of such a new owner to operate the divested plants more than the existing utility owners would decline.
Also, it is presumed that demand for electricity within California will not substantially increase either with or without divestiture. While some increased generation within California could be offset by a decrease in electricity imports from out of state, it is also possible that increased generation at one plant to be sold would be offset by a decrease in generation at another divested plant, or a decrease at another plant retained by PG&E.
This Initial Study assumes that each of the divested plants continues to operate within the parameters of its existing permits (e.g., water discharge permits and air emissions permits) because it is not reasonably foreseeable that operations would exceed those levels. Likewise, it is not foreseeable that particular units at the divested plants would be replaced (repowered) by new owners in a manner differently than by PG&E under restructuring without divestiture over the next decade. Operations in excess of permitted levels or repowering would, in any event, require new discretionary permits and environmental review.
The current plant owners could in the future operate up to their existing permitted levels (i.e., to the level allowed by the most constraining permit) without any additional approvals or environmental review. The precise manner in which PG&E would operate the three plants in the future restructured environment is difficult to predict. Under restructuring, the utilities may operate undivested facilities at higher levels than historical levels of operation, and could operate up to their permit limits. This means that increased generation at the plants proposed for divestiture could occur without divestiture. There are simply grounds for believing it is more likely to occur with divestiture.
As all of these elements indicate, it is highly uncertain at which plants generation would increase with divestiture as compared to without divestiture, or by how much generation would increase. The only conclusion that can be drawn is that overall there are incentives that create a tendency for the new owner of a divested plant to operate at higher levels than PG&E would operate that plant in the future.
Table 3.1 presents reasonably foreseeable capacity factors (the percentage of total plant capacity) for operation of the three plants in a restructured setting if they were not sold, but were retained by PG&E. These capacity factors are based on the SERASYMTM unit-specific, California-wide data set, which was processed by the SERASYMTM model to forecast plant operations in 1998. Table 3.1 also indicates the projected technically feasible maximum operating capacity factors
TABLE 3.1: CAPACITY FACTORS
for each plant (i.e., permitted levels minus forced outages minus planned and unplanned maintenance outages and de-rating outages). This Initial Study evaluates the impacts associated with the tendency of new owners of the divested plants to operate at higher levels than PG&E would operate the plants under restructuring without divestiture. The maximum levels at which new owners could operate are those presented as the technically feasible maximum capacity factors. However, for the reasons discussed above, it is not expected that operations would reach these levels at each plant, and operations may not reach such levels at any particular plant. It is merely the possibility that operations could increase within this range of capacity factors that is evaluated in this Initial Study. Increases in operations could also result in a minimal increase in employment at the plants.
It is not reasonably foreseeable that the currently non-operative and decommissioned off-shore fuel oil loading facilities at the Moss Landing plant and Morro Bay plant would be refurbished by new owners because of the high cost of refurbishing and monitoring such facilities, associated environmental constraints, and the low probability of a gas curtailment. In any event, refurbishment of these facilities would require issuance of new permits and accompanying environmental review. Other construction activities that are expected as a result of divestiture would be minor (i.e., construction of fences to separate properties being sold or retained). Non-physical changes would include subdivision of the properties as necessary to complete the sales.