The FCRPS ultimately will be operated in accordance with the decisions that result from the System Operation Review EIS. Until the SOR EIS is completed, FCRPS operations will be consistent with the decisions based on the 1992 Columbia River Salmon Flow Measures Options Analysis/EIS, the 1993 Supplemental EIS, and later supplements, if any, and consultation under the Endangered Species Act. Decisions regarding hydro-system operations and analyses of the environmental impacts of hydrosystem operations are being made in these other forums. (See Chapter 1, sections 1.5.1 and 1.5.3.)
This PacifiCorp Capacity Sale EIS will not focus on changes in hydropower operations, because the PacifiCorp contract is not a decision on particular hydropower operations. Instead, the contract is a system operational obligation to be met with all of the resources at BPA's disposal, including future acquisitions.
This EIS evaluates a range of alternatives and focuses on the mix of resources that may be used. The evaluation of the alternatives considers relying on the hydro system, as well as relying exclusively on thermal resources and/or acquisition of additional resources.
For impacts related to BPA system resource requirements under Alternative 1, the Proposed Action, analysis was performed on future capacity availability using the 1990 Pacific Northwest Loads and Resources Study (Whitebook) capacity projections for both medium and high load forecasts (see Appendix D). A high load study would have been sufficient to determine substantial impacts to the environment from use of resources to serve the proposed contract, but it was felt that a medium case was also useful to determine a more balanced analysis. The low load case was not included because the impacts of both the 1100 MW capacity contract and the additional 900 MW did not result in the need for BPA to acquire resources to cover either contract alternative. The Whitebook capacity projections were adjusted for capacity additions from the expected resource acquisitions (from the current Resource Program, specifically, 600 aMW of conservation) to meet energy deficits, and for potential reductions in availability of capacity from the FCRPS that might result from decisions in the SOR EIS. In addition, a cold weather adjustment was applied to account for periods of very cold weather in the Pacific Northwest, which result in high capacity demands. The same technique was applied to analyze future capacity availability under Alternative 3, Larger Capacity Sale, in which the proposed contract is for 2000 MW.
Because a final determination has not been made for potential reductions in availability of capacity from the FCRPS that might result from a decision to reduce hydro capability in the SOR EIS, these studies were used only as a general guide to assess potential outcomes. SOS Case 5(b) (see Appendix E) was selected as a reasonable representation for potential reductions in availability of capacity from the FCRPS. However, other outcomes of the SOR process are possible. Other SOSs being examined in the SOR process (see Appendix E) appear to diminish available capacity from the hydrosystem by large amounts, amounts similar in magnitude to that projected for SOS 5(b), but the decreases sometimes are projected to occur in other months when surplus capacity from the Pacific Southwest is not likely to be available. Therefore, to encompass the range of potential outcomes of the SOR process, this EIS analyzes a range of potential new capacity resource acquisitions from 0 to 1200 MW within which service to the PacifiCorp contract under alternatives 1 and 3 can be assumed.
For impacts related to PacifiCorp's system under alternatives 1, 2, and 3, BPA relied on PacifiCorp's Resource and Market Planning Program reports ("Balanced Planning for Growth." RAMPP-2, 1992, and RAMPP-3, 1993). These documents outline PacifiCorp's plans for resource acquisition.
The impacts of alternatives 4 and 5 are operational in nature and are analyzed qualitatively.
The alternatives in this EIS could create environmental effects from two sources. The first source is the acquisition (or deferral) of new thermal resources. The siting and building of a thermal power plant could create land effects as well as air and water effects. The second source for environmental effects arises from changes in operation of existing thermal resources, which could lead to air and water effects.
The Proposed Action and Larger Capacity Sale alternatives could lead to deferral of new thermal resources and changes in operation of existing thermal resources and therefore could affect land, air, and water resources. No action would lead to accelerated peaking resource development by PacifiCorp. The remaining two alternatives, Stricter Return Provisions and Variations in Hours of Peak Demand Available, do not change the size of the contract, but alter return conditions and hours of delivery. Therefore, they are less likely to create the need to acquire new thermal resources, but could lead to operational changes in existing thermal resources, and thus create air and water effects.
Figure 4-1: Summary of Environmental Effects for Each Alternative* (This figure not available in electronic format)
Each alternative is analyzed separately for its impacts on BPA's and PacifiCorp's power systems. Depending on the alternative, environmental effects may be felt in one system and not in the other. Where the acquisition of a new thermal resource is a possibility, the discussion is necessarily generic as there is no way to determine exactly where in the study area such a resource would be sited.
The long-term contract proposed under Alternative 1 would replace the expired 20-year contract, which had a capacity demand of 1127.3 MW, with a new contract demand of 1100 MW of capacity. The proposed contract would expire August 31, 2011.
(See Chapter 2, section 2.1, for more details.)
Since expiration of the old 20-year contract, capacity sales to PacifiCorp by BPA have continued via short-term arrangements that are essentially identical to the proposed long-term contract. Therefore, there would be no immediate, substantive change if the proposed action were implemented.
Currently, BPA could serve the long-term PacifiCorp capacity contract using capacity available from BPA resources that is surplus to other needs 96 to 98 percent of the time (Whitebook analysis). However, as preference loads grow, capacity that is available on the FCRPS now may be required to serve preference loads later. The issue becomes, what are the future resource implications of entering into the proposed 1100 MW long-term capacity contract with PacifiCorp, and how do those impacts differ from the impacts of other alternatives.
Deliveries
Deliveries are the generation and dispatch of peaking energy to PacifiCorp in amounts equal to their peak demand up to the limits of the proposed capacity contract. Peaking energy means the electric energy associated with the generation and delivery of capacity to PacifiCorp. There is a distinction between energy and capacity. Energy is a given amount of power produced over a period of time, expressed in kilowatthours (KWh) or larger units. Capacity is the instantaneous ability to generate a peak amount of power, expressed in kilowatts (KW) or larger units. It may be helpful to think of the energy/capacity relationship as being similar to a rental versus a sale, with capacity analogous to a rental, and energy analogous to a sale. With energy, as with a sale, a product is produced and sold to a customer who keeps possession. With capacity, as with a rental, the customer pays for the use of the product, and must return the product (in this case, the energy equivalent) after a specified time.
The analysis (see Appendix D) shows (under the medium load forecast) the long-term 1100 MW PacifiCorp capacity contract (Alternative 1) could be met with expected BPA resources in all but a few winter months under poor water conditions in the later years of the contract. Under the high load forecast (an event having an estimated probability of 5 percent), additional capacity would be required more frequently to meet the contract. BPA would expect to be short of capacity to meet the contract in November through February and in the first portion of April in the later years of the contract. Specifically, beginning around the year 2005, BPA would experience capacity shortages up to approximately 2400 MW under the poorest water conditions and high load growth.
Under this alternative, BPA would need additional capacity to meet the proposed PacifiCorp long-term contract only in the winter months for relatively short periods. BPA would make up this additional capacity with resources beginning with those of lowest cost--conservation acquisitions, efficiency improvements, and purchases from the Pacific Southwest. The California and Inland Southwest energy markets currently are surplus in capacity, and a number of utilities, including San Diego Gas & Electric and Los Angeles Department of Water and Power, are marketing this surplus. This especially is the case in winter, when California and the Inland Southwest market capacity from generation that is not being used to meet air conditioning loads. Therefore, BPA would not have to acquire new capacity resources to serve the contract, thereby avoiding the air, land, and water effects from the siting and building of a new thermal resource. Rather, BPA could meet the contract with economic resources and spot market purchases of capacity from the Pacific Southwest when needed. Such purchases would be delivered to BPA's system via the Intertie.
Purchases of capacity from the Pacific Southwest when needed to serve the PacifiCorp long-term capacity contract are not expected to have significant environmental impacts. The Final EIS on Non-Federal Participation in the AC Intertie (NFP EIS), pages 4-18 through 4-20, analyzed Pacific Southwest environmental effects of a variety of scenarios covering different types of transmission between the two regions. The NFP EIS analysis indicated that Pacific Southwest environmental effects were a function of net interregional transfer over seasons or annually. This is because the principal environmental implications come from the volume of energy generated, primarily from fossil fuel plants. If BPA purchased Pacific Southwest excess capacity to meet the PacifiCorp contract and BPA's other capacity loads, the energy losses would be returned within a short timeframe, such as a week, thereby not greatly changing either BPA or Pacific Southwest total generation.
Returns
Returns are simply the payback to BPA of energy it used to produce the capacity needed by PacifiCorp. The contract uses the term "peaking replacement energy" to express returns. Specifically, for purposes of this contract, peaking replacement energy is the amount of energy PacifiCorp is obligated to return to BPA equal to the electric energy associated with the delivery of surplus firm capacity.
Returns are normally delivered during nonpeak hours. These are called the off-peak or light load hour (LLH) periods. The LLH period is usually defined as the first six and last two hours of each workday including Saturdays, and all day Sundays and holidays.
To accept returns of peaking replacement energy, BPA must simultaneously back off an equivalent amount of energy being generated such that the generation displaced by the returned energy is stored in the system (in effect the returns are now serving a portion of BPA's load.) When an equivalent amount of peaking replacement energy has been returned by the customer to BPA's system, (i.e., within a 168 hour period), BPA is then considered to be "made whole" again with precisely the same energy content (with respect to the peaking contract) that it formerly had.
On occasion, BPA experiences conditions under which accepting returns of peaking replacement energy into its system is difficult. This can occur during conditions of spill and/or extreme light load conditions. For example, BPA sometimes experiences load conditions which are extremely light, (i.e., loads insufficient to meet the minimum generation requirements mandated by power plant license and/or physical operational characteristics.) These "extreme light load conditions" are infrequent and generally occur during the LLH periods. BPA is most likely to incur these problems with extreme light loads during the LLH periods of late summer/early fall months of August, September, and October. With regard to spill conditions, accepting peaking replacement energy would just add to the energy being spilled, and therefore BPA would not be "made whole" (e.g., as before delivery, the previous 168 hours), and the energy equivalent would be wasted. Aside from the required spills for fish flows, BPA is most likely to incur spill conditions during the late spring months of April, May, and June.
When these conditions arise BPA has several options to compensate for these problems. With respect to the proposed capacity contract, BPA has an option to limit the amount of returned peaking replacement energy by up to either 60 percent or 80 percent of hourly scheduled values, depending on the time of year. These special restrictions are specified in §5(b)(3) and §5(b)(4) of the proposed contract, and would usually be invoked only during the LLH periods. These limitations are designed to cover those times of the year during which BPA is most likely to experience problems in accepting returns of peaking replacement energy. It should be noted that any amount of peaking replacement energy subject to a limitation upon return is rescheduled for payback during a time that BPA has greater operational flexibility, (e.g., during a LLH that has greater operational flexibility, or the shoulder hours of a peak period), thus BPA is eventually "made whole." Limiting the rate of return has the same relative effect on improving the light load condition as if the load were raised (or at least maintaining the present load), thereby preventing or decreasing amounts of controllable spill that would otherwise have occurred. Another option that BPA has to compensate for spill or light load conditions is to increase the load through more direct means such as offering non-firm energy sales or making storage arrangements.
The environmental effects of imposing the special restrictions specified in §5(b)(3) and §5(b)(4) of the proposed contract are considered to be of short duration and pose no potential effect on resource development for either party to the proposed contract. The short-term environmental effects of invoking these restrictions are mainly hydro-related and as such will be dealt with in the SOR in sections relating to hourly flow changes. The impacts to thermal plant operations during periods of special restrictions on returns are minor as generation levels would be maintained at minimum operating levels anyway during periods of extreme light load conditions.
Returns during peak hours are permissible, but unusual. They are sometimes done concurrent with a scheduled peak delivery, a practice allowed by the proposed contract. PacifiCorp has the flexibility to return the peaking energy used during demand periods within 168 hours (7 days) subsequent to the scheduled demand. Thus peaking energy scheduled during one hour must be replaced by 168 hours later. Since the 168-hour period is successively expiring as each hour passes, a rolling return period continuously results. This rolling return may have environmental and economic consequences for both BPA and Pacificorp. PacifiCorp could request peaking demand of sufficient quantity to counter-schedule (simultaneously pay back) the amount of replacement energy needed from the previous 168 hours. Thus, the actual replacement of peaking energy from PacifiCorp's system could be delayed for an additional 168 hours or for as long as PacifiCorp chooses to continue the rolling return. In effect, this defers the time at which PacifiCorp must use its own system to return energy to BPA. During this period a number of conditions may have changed. For example, energy availability and price may have improved, benefiting PacifiCorp. Or available resources may have changed, allowing more marketing flexibility for PacifiCorp. If conditions on BPA's system and its wholesale markets are essentially the same during the rolled return period as when the return was normally expected (within the original 168-hour window), then the impacts on BPA would be inconsequential. However, such rolled return might have a negative effect on BPA when market conditions are not as favorable during the later period, or it might have a positive effect when market conditions are more favorable to BPA or if the returns are delayed to a time when the system is constrained in its ability to handle them. Such impacts were analyzed in depth by BPA during contract negotiation, resulting in a higher contract price to PacifiCorp as compensation for the rolling provision in the contract.
A similar 20-year capacity contract between BPA and PacifiCorp was executed on August 31, 1971. At its expiration, the contract demand was for 1127.3 MW. Since expiration of this contract, capacity sales to PacifiCorp by BPA have continued with short-term arrangements that are essentially identical to the proposed long-term contract in this alternative. Therefore, there would be no substantive change in capacity service from BPA to PacifiCorp if this alternative were implemented.
The Preferred Alternative would take advantage of the complementary characteristics of BPA's largely hydro system and PacifiCorp's largely thermal system by maximizing their different peaking characteristics. Specifically, BPA's hydro system produces proportionately large quantities of capacity versus energy, while PacifiCorp's system produces proportionately larger quantities of energy. The sale of surplus capacity to PacifiCorp may allow PacifiCorp to defer construction of new thermal resources that it may otherwise need in the absence of this contract. (See section 4.4.2, which discusses the No Action Alternative.)
The rolling return provision of the proposed contract (see paragraph 4.4.1.1, above) does not come without impact on PacifiCorp's system, since eventually all replacement of energy must be made up, and rolling diminishes the effectiveness of the contract for other purposes. However, it may assist PacifiCorp in getting through a period of unplanned outage until resources are operable once again, or until lower cost purchases are available. Such outages could force PacifiCorp to start up dirtier coal- or oil-fired resources, which could increase air and/or water pollution in their vicinity.
Because rolling larger balances owed to BPA increasingly diminishes the effectiveness of the peaking capability, it increases PacifiCorp's risk from unit outages and wholesale market swings. On the other hand, the ability to roll returns allows PacifiCorp to borrow time either to acquire economical resources or until resource performance is restored.
Under the No Action Alternative, BPA would not enter into any long-term capacity sale contract with PacifiCorp. BPA would use the flexibility of its system on an ongoing basis to support additional nonfirm sales, to perform more seasonal storage transactions, and to make short-term spot capacity sales or exchanges, including potential short-term capacity sales to PacifiCorp.
FCRPS operations under the No Action Alternative would be consistent with hydro operations decisions being made in other forums (see section 4.1). BPA would not acquire resources under the No Action Alternative of different types or in different quantities than determined through the Resource Programs EIS and Record of Decision (ROD). BPA resource acquisitions would continue to be driven by load growth and need for future sources of energy. Neither would operation of must-run resources such as WNP-2 be affected. However, operation of some resources may be somewhat different under the No Action Alternative than under the other alternatives because non-hydro FCRPS resources
(i.e., Federal thermals and alternative resources) would be operated to complement a hydro operation that is different from the other alternatives. For example, in a low water year, discretionary operations under the No-Action Alternative may use a Federal thermal resource to generate a portion of the load normally allocated to the FCRPS hydro generators. Energy thus saved by the FCRPS generators would be retained in storage. It is not possible to quantify these differences because the system operation under "no action" cannot be precisely defined.
Resource Development
While no action on BPA's part has little definable effect on the environment, the No Action Alternative would require PacifiCorp to take action to meet its capacity needs. In the short term, PacifiCorp may attempt to purchase up to 800 aMW (plus
15 percent reserves) of capacity on a short-term basis from BPA. Also in the near term, PacifiCorp might seek to contract with other utilities that have excess capacity, make fewer secondary sales, and operate its coal plants at lower, less efficient levels during off-peak hours. The principal costs of this short-term strategy would be purchased capacity charges, increased operating cost, and lost wholesale revenues. In the long term, PacifiCorp would need to secure its own resources and/or make long-term capacity arrangements with other utilities to meet its capacity needs. This may include the building of new thermal resources, which, depending on type, could increase air and/or water pollution in addition to land impacts from building.
In the short term, BPA could provide sufficient hydro capability (when available) to market 800 aMW (plus 15 percent reserves) to PacifiCorp from the FCRPS. Such sales would occur within whatever constraints might be applied to the FCRPS through the SOR process and the 1992 Flow EIS and its supplements. Impacts of such short-term sales would be limited to the hydro system and therefore are not addressed in this EIS. BPA would have to decide if such short-term capacity sales to PacifiCorp would be the highest and best use of the FCRPS system before making such sales, and would have to comply with laws giving public utilities and cooperatives preference to such capacity.
In the longer term, PacifiCorp probably would develop resources independent of BPA to meet its capacity need. PacifiCorp plans for resources indicate a need of 900 MW of capacity resources in addition to the 1100 MW long-term capacity contract. In its "Balanced Planning for Growth, Resource and Market Planning Program" (RAMPP-2, PacifiCorp, May 14, 1992), PacifiCorp's action plan included initiating siting and permitting for up to 450 MW of simple-cycle combustion turbine (SCT) resources. An acquisition of 150 MW of peaking resources in Arizona Public Service Company's service area that was called for in RAMPP-2 has already taken place. The RAMPP-2 study was done at a time when the long-term capacity contract with BPA was expected to be for 1400 MW. Therefore, PacifiCorp has a total need for capacity, or peaking, resources within its planning horizon of 2000 MW, of which 1100 MW may come from the proposed BPA long-term capacity contract. If the No Action Alternative were implemented, PacifiCorp would likely need to acquire a total of about 1850 MW of combustion turbine resources in addition to the peaking resources from Arizona Public Service, or about 750 MW more in combustion turbines than if the proposed long-term contract were implemented.
For purposes of the analysis, it was assumed that the gas-fired SCTs that would be installed by PacifiCorp have the air pollutant emission characteristics detailed in tables 2, 3, and 4 of RAMPP-3 (PacifiCorp, Generation Resources, Generation Engineering, April 1993, Revision 1) for large units. Pertinent data from these tables is reproduced in this EIS as Tables 4-1, 4-2, and 4-3. PacifiCorp has also stated that one of the simple-cycle units could be converted to a combined cycle combustion turbine (CCCT) within the lifetime of the contract. Tables 4-1, 4-2, and 4-3 also give emission data for combined cycle units. The expected annual load factors would be 10 to 20 percent for simple-cycle units and 60 to 80 percent for combined cycle units. For the analysis, 20 percent and 60 percent annual load factors were used for simple and combined cycle units, respectively. PacifiCorp would expect to site the first 300 MW (nameplate) of capacity in the western part of their service area. Likely locations would be in southern Oregon near Malin or Klamath Falls; and in south-central Washington/north-central Oregon near the intersection of major natural gas pipelines. After the initial 300 MW of development, future facilities would likely alternate between the aforementioned west-side sites and east-side sites in southwestern Wyoming or northern Utah.
For purposes of analysis, development of the new PacifiCorp capacity resources without the long-term capacity contract with BPA is assumed to occur as shown in Table 4-4.
With the long-term capacity contract, only 750 MW of capacity resource development would need to be undertaken by PacifiCorp. If the contract were implemented, it was assumed for purposes of analysis that future capacity resource development by PacifiCorp would occur as shown in Table 4-5.
Table 4-1: PACIFICORP - RAMPP-3 SUPPLY-SIDE PORTFOLIO: TABLE 2 (Partial) - Oregon/Washington
Emissions (lb/MWh) |
Options |
MW Capacity |
Average Net Plant Heat Rate (BTU/kWh) |
SO2 |
Particulate |
NOx |
CO2 |
Gas Fired Plants |
||||||
Large CCCT |
225 |
7518 |
0.0043 |
0.0218 |
0.6781 |
1000 |
Large SCCT |
159 |
11,336 |
0.0065 |
0.0329 |
1.0224 |
1508 |
PACIFICORP - RAMPP-3 SUPPLY-SIDE PORTFOLIO: TABLE 3 (Partial) - Utah
Emissions (lb/MWh) |
Options |
MW Capacity |
Average Net Plant Heat Rate (BTU/kWh) |
SO2 |
Particulate |
NOx |
CO2 |
Gas Fired Plants |
||||||
Large CCCT |
191 |
7518 |
0.0043 |
0.0218 |
0.6781 |
1000 |
Large SCCT |
135 |
11,336 |
0.0065 |
0.0329 |
1.0224 |
1508 |
Table 4-3: PACIFICORP - RAMPP-3 SUPPLY-SIDE PORTFOLIO: TABLE 4 (Partial) - Wyoming
Emissions (lb/MWh) |
Options |
MW Capacity |
Average Net Plant Heat Rate (BTU/kWh) |
SO2 |
Particulate |
NOx |
CO2 |
Gas Fired Plants |
||||||
WCC Large CCCT |
173 |
7518 |
0.0043 |
0.0218 |
0.6781 |
1000 |
WCT Large SCCT |
122 |
11,336 |
0.0065 |
0.0329 |
1.0224 |
1508 |
NOTES, Tables 4-1, 4-2, and 4-3:
1. Combustion turbines assume 25 ppm NOx
2. Emissions based on average as-delivered mountain fuel analysis
3. Plant capacity reflects net MW output rating
4. Natural gas heat rates (HHV) and emissions have been adjusted 5 percent to 7.5 percent based on intermediate/peaking use
The Endangered Species Act of 1973, as amended (16 USC 1536), requires Federal agencies to ensure that their actions do not jeopardize endangered or threatened species or their critical habitats. In compliance with Section 7, BPA requested from the U.S. Fish and Wildlife Service (USFWS) a list of endangered and threatened plant and animal species in the affected environment. This information was provided by the appropriate USFWS Field Offices in Idaho, Montana, Wyoming, Nevada, Oregon, and Washington, and is presented in Appendix B.
Table 4-5 encompasses a total of 750 MW of combustion turbine development, with the numbers of plants distributed as evenly as possible over the four areas in which PacifiCorp indicated they would be likely to site capacity resources.
Assuming development of resources as in Tables 4-4 and 4-5, annual quantities of air pollutant emissions can be computed using emission factors appropriate for the type, size, and location of the resource from Tables 4-1, 4-2, and 4-3. These results are shown in Table 4-6.
Table 4-7 shows the estimated annual quantities of air pollutants which would be produced, by region, if 750 MW of PacifiCorp resource development were to occur as shown in Table 4-5. These quantities represent amounts which may be expected to occur even with implementation of the proposed long-term capacity contract. Tables 4-8 shows the additional amounts of air pollution from PacifiCorp resources which may occur if the proposed long-term contract is not implemented, i.e., under the No Action Alternative relative to the proposal.
Table 4-4: New PacifiCorp Capacity Resource Development Under the No Action Alternative
Malin/Klamath Falls Area |
North-central Oregon/ South-central Washington |
Northern Utah |
Southwestern Wyoming |
Plant 1: |
Plant 2: |
Plant 3: |
Plant 4: |
Plant 5: |
Plant 6: |
Plant 7: |
Plant 8: |
Plant 9: |
Plant 10: |
Plant 11: |
Plant 12: |
Upgrade to |
Plant 13: |
1/ One of the previous plants constructed in the Malin/Klamath Falls area is upgraded to a combined cycle facility, increasing its capacity to 225 MW.
2/ Balance needed to make 1850 MW. In actuality, another large, 159 aMW SCT would likely be constructed, since a large unit would be more efficient, but only 59 MW can be attributed to the need for capacity projected. In the analysis, the impacts of this unit were prorated, with 37 percent of the impacts being included with the impacts of no action.
Table 4-5: New PacifiCorp Capacity Resource Development Assuming Implementation of the Proposed Long-Term Capacity Contract With BPA
Malin/ Klamath Falls Area |
North-central Oregon/ South-central Washington |
Northern Utah |
Southwestern Wyoming |
Plant 1: |
Plant 2: |
Plant 3: |
Plant 4: |
Upgrade to CCCT, 66 MW1/ |
Plant 5 |
1/ One of the previous plants constructed in the Malin/Klamath Falls area is upgraded to a combined cycle facility, increasing its capacity to 225 MW.
2/ Balance needed to make 750 MW. In actuality, another large, 159 aMW SCT would likely be constructed, since a large unit would be more efficient, but only 109 MW can be attributed to the need for capacity projected. In the analysis, the impacts of this unit were prorated, with 69 percent of the impacts being included with resource impacts that would occur from PacifiCorp capacity resource development, even with the proposed 1100 MW BPA contract.
Table 4-6: Annual Emissions (Tons/Year) From 1850 Megawatts of PacifiCorp Capacity Resources by Area
Pollutant |
Malin/ Klamath Falls Area |
North-central Oregon/ South-central Washington |
Northern Utah |
South-western Wyoming |
Total |
Sulfur Dioxide |
2.90 |
3.05 |
2.31 |
2.08 |
10.3 |
Particulate |
14.7 |
15.4 |
11.7 |
12.6 |
54.4 |
NOx |
457 |
480 |
363 |
328 |
1628 |
Carbon Dioxide |
681,000 |
708,000 |
535,000 |
483,000 |
2,407,000 |
Table 4-7: Annual Emissions (Tons/Year) From 750 Megawatts of PacifiCorp Capacity Resources by Area
Pollutant |
Malin/ Klamath Falls Area |
North-central Oregon/ South-central Washington |
Northern Utah |
South-western Wyoming |
Total |
Sulfur Dioxide |
2.54 |
1.53 |
0.77 |
0.46 |
5.30 |
Particulate |
12.9 |
7.72 |
3.89 |
2.33 |
26.8 |
NOx |
401 |
240 |
121 |
72.5 |
834 |
Carbon Dioxide |
591,000 |
354,000 |
178,000 |
107,000 |
1,230,000 |
Table 4-8: Increase in Annual Emissions (Tons/Year) by Area With No Action Relative to the Proposed Contract
Pollutant |
Malin/ Klamath Falls Area |
North-central Oregon/ South-central Washington |
Northern Utah |
South-western Wyoming |
Total |
Sulfur Dioxide |
0.36 |
1.52 |
1.54 |
1.62 |
5.0 |
Particulate |
1.8 |
7.68 |
7.81 |
10.27 |
27.6 |
NOx |
56 |
240 |
242 |
255.5 |
794 |
Carbon Dioxide |
90,000 |
354,000 |
357,000 |
376,000 |
1,177,000 |
Information about other types of environmental impacts for CTs is available in the Resource Programs Final EIS (Final Environmental Impact Statement, Resource Programs, Vol. 1, Environmental Analysis, Chapter 3, pp. 3-58 through 3-64). Impacts relating to the extraction and transportation of natural gas, which serves as fuel for the facilities, and are not specific to the site of the plant (i.e., they generally occur off site) are shown in
Table 4-9.
PacifiCorp is investigating the use of peak management techniques that may reduce the need for peaking generation. (PacifiCorp, Peak Management, October 29, 1993, prepared by Carole Rockney and Bruce Werner.) Recommendations for implementing peak management techniques include (1) investigating and implementing system efficiency improvements; (2) investigating new generation pumped storage technology; (3) demand-side programs, including energy conservation, investigation of load control options through pilot tests, and study of targeted, local area direct load control in areas where transmission and distribution capacity are constrained; and, (4) studying, offering, and promoting pricing mechanisms to better reflect time-of-day costs. To the extent that these efforts may reduce peak load, the need for combustion turbine generation, and the environmental impacts thereof as described above, could also be reduced under either the no action alternative or the proposed capacity contract. Impacts of load management techniques and customer system efficiency improvements are discussed in the Resource Programs Final EIS, Vol. 1, pp. 3-87 through 3-91. Load management techniques are generally viewed as environmentally benign. Customer system efficiency improvements may have some environmental effects related to potential improper disposal of old, inefficient transformers, effects on land use and habitat when the efficiency improvement involves construction, such as when an old, inefficient substation is replaced with a new one at a different site, and potential for changes in electromagnetic fields effects from facilities. However, these can only be evaluated on a site-specific basis.
From the perspective of impacts to new resource development and operation, the No Action Alternative has more environmental consequences, since No Action would be projected to result in construction and operation of eight additional combustion turbine facilities. The impacts on air quality would be tempered by the fact that the facilities would be required to meet air quality regulations designed to protect human health and welfare. The primary air quality impact therefore may be a reduction in future opportunities to locate other facilities that produce air pollution in those areas, as specified in Tables 4.4 and 4.5, where PacifiCorp would be likely to site facilities. Other impacts from the construction of resources under the No Action Alternative probably would be minor. The combustion turbine facilities
Table 4-9: Impacts Relative to Natural Gas Production and Transportation for
1850 MW |
750 MW |
|||
Estimated Impacts |
On-Shore Gas Extraction |
Gas Transportation1/ |
On-Shore Gas Extraction |
Gas Transportation1/ |
Air Pollutants |
Oxides of Sulfur tons/year |
594 |
0.250 |
279 |
0.117 |
Oxides of Nitrogen, tons/year |
35.0 |
166 |
16.4 |
78.0 |
Particulates, tons/year |
0.81 |
0.38 |
Water Pollutant Discharges |
Biological Oxygen Demand, tons/year |
0.69 |
0.32 |
||
Chemical Oxygen Demand, tons/year |
4.63 |
2.17 |
||
Oil & Grease, tons/year |
14.2 |
6.69 |
||
Chromium, tons/year |
0.038 |
0.018 |
||
Zinc, tons/year |
0.013 |
0.0059 |
||
Total Dissolved Solids, tons/year |
191 |
89.5 |
||
Chloride, tons/year |
35.6 |
16.7 |
||
Sulfate, tons/year |
28.8 |
13.5 |
Land Effects |
Acreage Requirements per year |
15.6 permanent, 20.0 temporary |
2613 |
7.3 permanent, 9.4 temporary |
1226 |
Solid Wastes |
Drill Cuttings, tons/year |
1400 |
657 |
||
Drilling Mud, acre/ft. |
3.63 |
1.70 |
Employment |
Construction, employee/years |
18.1 |
281 |
8.51 |
132 |
Operations, employees per year |
1.81 |
8.13 |
0.88 |
3.81 |
Occupational Safety & Health |
O & M Injuries per year |
4.8x10-5 to 1.4x10-3 |
6.6x10-5 to 1.1x10-4 |
2.3x10-5 to 6.4x10-4 |
3.1x10-5 to 5.0x10-5 |
O & M Deaths per year |
5.6x10-7 to 1.4x10-5 |
2.3x10-7 to 1.9x10-6 |
2.6x10-7 to 6.5x10-6 |
8.8x10-8 to 8.8x10-7 |
1/ For gas transportation, data missing in the columns are either not relevant to that activity, or factors to compute the relevant value are not provided in the Resource Programs Final EIS.
probably would be sited in areas zoned for industrial use and combustion turbine facilities do not require large amounts of land or water. Noise from combustion turbine facilities can be a concern, but the facilities are likely to be muffled to meet noise standards, and are not likely to be very near noise-sensitive properties. Ultimately, however, the impacts of potential combustion turbine development by PacifiCorp under the No Action Alternative, or the proposal for that matter, are highly site-specific and can not be identified precisely without knowing the actual sites or more about the particular characteristics of the facilities as they would be built. Therefore, some types of impacts, such as impacts on cultural resources, aesthetics, recreation, threatened or endangered species, etc., cannot be identified at this level of analysis. Such impacts would be a consideration in the siting and licensing processes for the generating facilities, and may be precluded or mitigated as a result.
Air emissions from existing and new power plants may impair vegetation as discussed in BPA's Resource Programs EIS, Volume II, Appendix F, Section 8. Other direct effects to vegetation are to be expected with the development of energy facilities such as new plants, transmission lines, or substations. Predicting such impacts is beyond the scope of this document, since locations of such facilities cannot be defined.
However, some impacts of the No Action alternative are not site-specific. Global warming, for example, is not site-specific, since it is a cumulative effect of worldwide releases of greenhouse gases. The No Action Alternative is of greater concern than the other alternatives from the perspective of global warming, since more carbon dioxide would result. The No Action Alternative would also require more fuel, primarily natural gas, a depletable natural resource, and would result in greater impacts from the infra-structure needed to supply it.
Operational Changes Related to Other PacifiCorp Resources
PacifiCorp expects to use the contract to shape about 2.7 million MWh of generation per year from off-peak to on-peak. Even without a firm contract under the No Action Alternative, PacifiCorp intends to use short-term and non-firm BPA capacity in a similar fashion (to the extent that capacity is available and usable).
In the worst case for PacifiCorp, it would not get any BPA short-term capacity and would have to provide substantial amounts of on-peak generation with combustion turbines. In this scenario, thermal units would have to be backed down in the off-peak hours. The first resources to be displaced (both with and without the contract) include Gadsby and the new SCTs. In the early years, the second resource to be displaced would be the higher-cost coal plants, e.g., Centralia, Naughton, and Cholla. As the CCCTs are added, they become the second group of resources to be displaced, and the coal plants would be third. As noted above, the bulk of the impact is on the baseload resources, i.e., the CCCTs and coal plants.
PacifiCorp expects competition for BPA's non-firm capacity to be most intense from mid-December to mid-February. The following describes the impact on system operation when PacifiCorp is unsuccessful in acquiring BPA's non-firm capacity.
Without the contract, there would be an increase in energy from unusable off-peak thermal generation that was previously shaped to peak hours. More energy would be generated on-peak by the new resources that PacifiCorp acquires. In the near term, the off-peak energy would be "trapped" at the coal plants, resulting in lower production factors. (PacifiCorp's coal plants have one of the highest production factors in the industry.) As new resources are acquired to cover the growth in load, the "trapped" energy would shift to the new resources with their higher incremental cost.
There would be an increased use of thermal plants to serve short-term peaking needs. In the near term, these plants would be other utilities' older oil and gas-fired boilers or combustion turbines, which produce higher emissions than newer and cleaner thermal plants. For example, PacifiCorp has secondary rights to combustion turbines with Black Hills Power & Light and with Arizona Public Service. Eventually, this peaking requirement would be served by more efficient new SCTs.
There would also be a shift in PacifiCorp's ability to displace other utilities' high-cost thermal. There would be fewer on-peak hours and more off-peak hours with surplus energy. Since the assumption is that without the contract with PacifiCorp, BPA would sell the same capacity and storage in the non-firm market, there should be a complementary shift in some other utility's surplus energy.
Under this alternative, BPA would contract for amounts up to an additional 900 MW of contract demand with PacifiCorp and/or other utilities under terms similar to the proposed contract. Based on current forecasts, BPA could serve an additional 900 MW by using surplus capacity that is available from BPA resources. However, FCRPS operations may be redefined in the SOR process (see section 4.1), and interim annual operating schemes being formulated through supplements to the 1992 Flow EIS. In addition, as preference loads grow, capacity that is now available on the FCRPS may be required to serve preference loads later. The issue for this alternative is what are the future resource implications of contracting to supply PacifiCorp and/or other utilities with up to a total of 2000 MW of capacity.
Whether the entire 2000 MW is delivered to PacifiCorp, or whether the additional amounts up to 900 MW of capacity are delivered to other utilities, the impacts on BPA's system are essentially the same. BPA applied the same analytical technique used for the proposed contract to assess future capacity availability to serve a contract for an additional amount up to 900 MW of capacity. (See section 4.2 and Appendix D.)
The analysis assumed poor water conditions and a medium load forecast. The results of this analysis show that a long-term
2000 MW capacity sale (the initial 1100 MW PacifiCorp contract plus an additional 900 MW) could be met with expected BPA resources 90 percent or more of the time in all months of the year except February, March, and April. In these months, BPA could meet a 2000 MW contract approximately 80 percent of the time. In years where these water conditions prevailed and for these months, BPA would need to acquire capacity to serve the contract, probably by purchasing from the Pacific Southwest. Alternatively, BPA could choose to acquire the output of a thermal resource to serve the contract under the above conditions.
A second analysis was conducted assuming the same poor water conditions and a high load forecast. Under this scenario, BPA could serve a 2000 MW capacity contract (the initial 1100 MW contract plus the additional 900 MW of capacity) with expected resources 90 percent or more of the time in all months of the year except February, March, April, and November. In these months, BPA could meet the contract 60 to 80 percent of the time. Again, BPA would need to acquire capacity to serve the contract in these months, probably by purchasing from the Pacific Southwest. Under these conditions, where less of the contract could be met with available resources, it could be cost effective for BPA to acquire the output of a resource to serve this contract and forecasted future load growth. Should the long-term outlook warrant such a decision, BPA could implement the 5-year notification of recall provision (as provided in §7(b)(1) of the proposed contract).
With additional contract demand above 1100 MW, PacifiCorp's need for capacity resources would be proportionately reduced.
With a capacity contract for 2000 MW (the initial 1100 MW contract plus the additional 900 MW of capacity), PacifiCorp's planned summer capacity needs would be met through the term of the proposed contract. PacifiCorp would not need to develop capacity resources of its own for that period. The development of the 1100 MW of SCT resources as described for the No Action Alternative (see section 4.4.2) would not occur, and the developmental and operational environmental impacts related to these facilities and described in section 4.4.2 would not take place. Nor would the additional 450 MW of SCT resources projected by PacifiCorp to be needed by 1998 be developed, saving the environmental impacts of the development of these resources.
If BPA contracts for all or part of the additional 900 MW to other utilities, specific environmental effects are hard to assess. It is reasonable to adopt the assumption that PacifiCorp is typical of most utilities in their resource portfolios and development. Therefore, if the 900 MW of capacity were marketed to other Pacific Northwest entities, the pattern of displacement of thermal resource use and development would be similar.
This alternative is the same as the Proposed Action except BPA would be allowed to unilaterally impose stricter return of peaking replacement energy provisions. In lieu of the 168-hour return in the proposed contract (§5(b)(1)), BPA could either: (1) require a 24-hour return, or (2) impose an end-of-week return deadline whereby all peaking replacement energy must be returned by the 2400 hour on Sunday. These return provisions are different from the return provisions under the proposed action and as such have less value to PacifiCorp because this tends to degrade the operating flexibility of the proposed contract.
In order to facilitate these types of capacity sales, BPA would still operate and utilize flexibility's of the FCRPS in accordance with its existing operational criteria and limitations. Therefore, any capacity sale and its return provisions (whether a 24-hour return, 168-hour return, or end-of-week return) would not cause the system to be operated inconsistently with the normal operational limits of the FCRPS.
Under certain extreme system conditions (e.g., cold snap and/or extended WNP-2 outage combined with critical water year flows), any capacity product sold on a firm, long-term basis might require BPA to acquire off-system purchases during some winter months. The probability of this situation occurring is difficult to determine; however, overall revenues from the capacity sale should outweigh any risks associated with these off-system purchases.
Under the 24-hour return scenario, PacifiCorp would have up to 24 hours to make returns on all peaking energy (the electric energy associated with the delivery of surplus firm capacity) taken from BPA. This is markedly different from the typical operating strategy associated with the 168-hour return in the proposed contract, in which PacifiCorp may choose to defer some returns until the weekend or later. As a result, BPA would not experience an increasing energy debt balance throughout the weekdays followed by replacement over the weekends and holidays. This scenario provides the most certainty for operational planning purposes for BPA's system. By having greater control of its loads, BPA could achieve greater efficiencies in the use of its resources. This may translate to lower production cost and improved availability factor (measure of a resource's in-service/out-of-service ratio). These efficiencies could have environmental benefits for BPA, such as improved air and water quality. However, because this provision severely restricts PacifiCorp's operational flexibility compared to the proposed contract, it would likely result in the need to renegotiate the pricing structure, resulting in a revenue reduction for BPA.
End-of-Week Return (Sunday Deadline) Provision
PacifiCorp desires more operating flexibility than the 24-hour return provision allows. The end-of-week scenario would require that all peaking energy taken by PacifiCorp during a Monday-to-Sunday week be returned to BPA by Sunday midnight. This arrangement would provide additional flexibility over the 24-hour return provision, but would eliminate the rolling return capability under the proposed contract, as discussed in section 4.4.1.1.
The elimination of the rolling return capability would mean that return of peaking energy could not be deferred into the next week or subsequent weeks. Therefore, BPA could always plan system operations assuming that it would be in energy balance by the end of each week.
Under this arrangement, BPA would benefit over the proposed sale by gaining improved week-to-week certainty in planning and in reduced economic exposure under certain system conditions. BPA's revenues from an end-of-week return scenario, although less than the proposed sale, would be greater than the 24-hour return scenario.
A 24-hour return for peaking replacement energy means that capacity generally delivered to PacifiCorp during the daytime heavy load hours (HLH) generally is returned that night in the light load hours. In this mode, the contract would perform as a firm
24-hour load-factoring service, not unlike the firm storage service often offered by BPA. Under an abnormal condition on PacifiCorp's system (e.g., loss of thermal or transmission resources), it is likely that peaking energy might be taken in all hours one day, then returned all during the next day from other resources. In this mode, the energy would simply be borrowed today for return tomorrow. In either case, this service offers PacifiCorp no assistance in meeting a cold snap or a multiple-day resource outage. PacifiCorp has very little need for a 24-hour return service and would likely value it considerably lower than the proposed contract.
End-of-Week Return (Sunday Deadline) Provision
Under the end-of-week return scenario, the peaking energy return balance must be zero each Sunday midnight. This means that PacifiCorp could make no peaking energy returns during the Monday early morning LLH period, probably resulting in reduced thermal generation during these periods. This condition would not exist on the other days of the week, since peaking energy could be returned for capacity deliveries taken on the prior day. Further, PacifiCorp routinely requires peaking energy during Sunday daytime to meet system requirements. Utilization of capacity on Sundays under this option would necessarily be limited to that which could be returned by midnight that same day.
PacifiCorp requires the rolling return capability to cover forced thermal and/or transmission outages, which are unpredictable and can leave PacifiCorp deficient for periods extending for a few days or longer. During such periods, returning all the energy to BPA by a specified deadline would be very difficult, while deferral of returns allows PacifiCorp to recover its system before BPA must be made whole again.
While PacifiCorp would see increased flexibility versus the
24-hour return arrangement, an end-of-week return product would have significantly reduced value in meeting their system needs because it provides only very limited capacity coverage for unit outages on weekends and for other system requirements.
Cumulatively, this would result in significantly fewer capacity transactions with PacifiCorp compared to the proposed action. To the extent that these transactions involve thermal resources, impacts to air quality and perhaps land use related to new resource development may be reduced.
The proposed contract allows up to 50 hours of peak demand. Under this alternative, BPA would extend the number of hours of peak demand, thereby making a greater amount of peaking energy available to PacifiCorp each day and each week, while keeping the contract demand limit the same as in the proposed contract. Variations of less than the proposed contract would have impacts of lesser severity.
This alternative, by necessity, also relaxes some terms of the proposed contract. Specifically, the restrictions on return of peaking replacement energy in March through October as stated in §5(b)(3) and §5(b)(4) of the proposed contract would be eliminated. This is a practical measure made necessary because of the difficulty that PacifiCorp would otherwise experience in making returns of replacement energy within the off-peak periods due to the magnitude of peaking energy available under this alternative.
For example, if it could be assumed that BPA increased the number of hours of peak demand to 72 hours, a common hourly amount requested by some BPA customers, the amount of peaking energy available to PacifiCorp would then be an amount equal to the proposed contract demand of 1100 MW times 72 peak hours. Total peaking energy would thus be 79,200 MWh. Incurring an obligation to return this magnitude of peaking replacement energy in other than peak hours would be difficult for both the customer and for BPA. A peak demand stretched to 72 hours is more suitable, from an environmental perspective, for smaller capacity contracts of, say less than 200-300 MW of peak demand. Small peak demand contracts are less operationally significant relative to BPA's overall capabilities, and therefore pose little or no effect to BPA's load shape. Larger peak demand contracts, of the magnitude of the proposed action with PacifiCorp, are of greater concern when coupled with the capability to make up to 72 hours of peak demands because of their potential to affect the load shape in a manner that may cause radical load swings that are potentially harmful to the system. This is of greatest concern during the transitional periods between the peak load period and the off-peak period. Full utilization of a capacity contract with 72 hours of peak demand would have only 96 hours (within the 168 hour payback period) to repay the peaking obligation. Note that 72 of this 96 hours represents the commonly defined LLH during a 168 hour week (See the definition for light load hours in
Chapter 7.) Since, by definition, the LLH periods are hours other than the HLH, the customer in this situation would have a little more than half of the 168 hour period during which to return the peaking energy replacement Thus, a customer fully utilizing a capacity contract with 72 hours of peak demand would need to begin making returns of peaking replacement energy immediately after the HLH period, sometimes within the hour, after having just accepted a peak delivery of capacity during a preceding HLH. For capacity contracts with relatively small peak demand limits relative to their system capabilities this may not be operationally significant, but capacity contracts with large peak demand limits may experience operational problems. The consequence of transitioning magnified load swings from large amounts of capacity deliveries to large amounts of returns in a short time span is a whip-sawing effect on both parties systems in a manner not consistent with normal operational practices The load swings for both the customer and for BPA during these transition periods would be abrupt and inconvenient at best, and perhaps harmful at worst. This may have consequential short duration environmental concerns for fish and wildlife, water quality, recreation, navigation, and the like. These short duration load swings are mainly hydro-related for BPA and as such will be dealt with in the SOR in sections relating to hourly flow changes.
Peaking energy returned in LLH varies in value depending on time of year and time of week. For example, peaking energy returned in January LLH during a cold spell is more valuable than the same energy returned in May or June LLH when weather is mild and the hydro system is experiencing spring runoffs. Alternatively, loads in the months of late August and September are traditionally the lightest of the year, so problems associated with minimum generation during the LLH period are more likely during this period.
Therefore, the increase in the return of peaking energy from 55,000 MWh to as much as 79,200 MWh makes this return energy less valuable to BPA during periods when BPA has extreme light load conditions and is energy surplus. Since this alternative does not alter the contract demand or price of capacity, BPA is made less whole when it cannot accept returned peaking energy.
Increased returns of peaking replacement energy can sometimes be a problem purely due to economic considerations. For example, BPA may be in a situation where it must purchase energy (as it was during the winter cold-snap in the later months of 1992 and early months of 1993), and make concurrent restrictions on amounts of peaking energy replacement being returned to BPA because of minimum generation problems. The restricted amounts of peaking energy replacement then must be rescheduled for return during other hours. This problem arises during such periods whenever BPA is making LLH purchases of needed energy when prices are lowest, but could be prevented from purchasing all the energy that the Federal system would otherwise be able to accept due to minimum generation problems on the FCRPS. Minimum generation problems in this case are caused by the competition of incoming energy purchases (that have the effect of reducing FCRPS generators to their lowest allowable levels) and simultaneous incoming peaking replacement energy being returned to BPA. Purchases must take priority in this case because of the economic considerations and the fact that returns can be made during other hours. The environmental impacts to BPA associated with the operation of the contract in this situation are caused from assumed decreases in Federal generation levels during peak or shoulder peak periods, as the deferred peaking replacement energy is returned to BPA. To the extent that this generation is from a thermal resource, the emissions would be less during this same period. However, overall emissions would remain the same, as only the time period for returns has changed, not the obligation to return peaking energy.
By increasing the number of hours of peak demand, PacifiCorp, under this alternative, could serve more of its peak loads, thereby deferring the need to develop and/or operate higher priced thermal resources that may be more environmentally damaging.
On the other hand, if PacifiCorp took advantage of an increase in the number of hours of peak demand, it would have to stand ready to make up to 79,200 MWh of peaking energy returns. This would require increased operations of their resources or additional purchases. If these purchases or operations are from thermal units, then this would result in longer hours of emissions in a given week. Additionally, increased resource operations may need to be done during periods when they otherwise would not be in operation. This may impact other scheduling considerations.
Cumulative impacts related to the range of alternatives considered in this EIS are mostly associated with the No Action Alternative. This section deals with these impacts for all the alternatives.
There are identifiable cumulative impacts associated with the No Action Alternative, since PacifiCorp would likely undertake substantial resource development to meet their capacity needs. However, it is impossible to address some cumulative impacts definitively because it is not known precisely where these resources would be built.
Global warming is a cumulative impact that can be addressed on a non-site-specific basis. It is caused by worldwide releases of carbon dioxide and other greenhouse gases, and would be accelerated by the operation of new resources, since they would result in additional carbon dioxide releases.
The need for additional generation resources by PacifiCorp under the No Action Alternative would increase competition for sites for generating facilities. These may occur because of interactions with air pollutants produced by power generating projects, including perhaps some from which BPA may acquire power. There may be similar interactions with pollutants from industrial and commercial developments, increases in traffic, and other facets of continued economic development. There would be cumulative impacts on air quality in the vicinity of the resources which would be developed. Ambient air quality standards and rules for the prevention of significant air quality deterioration would be approached or reached sooner with no action in the vicinities of the resources which would be developed.
Consumption of resources, particularly natural gas, is also a cumulative impact, since many other activities consume the same resources as would the construction and operation of the generating facilities PacifiCorp would need under the No Action Alternative.
The other alternatives analyzed in this EIS do not have the generating resource development implications of the No Action Alternative. Although some additional resources may be required to support the contract at times of shortage of capacity from BPA's system, these would most likely be secured from purchases from existing resources in California, and new resources are not likely to be built. To the extent some resources in California might sometimes be operated to meet a BPA purchase, there may be small cumulative impacts related to air quality, global warming, and fuel consumption, but these would be expected to be negligible.
The Larger Capacity Sale Alternative may preclude or defer some additional generating resource development, and may, therefore, result in a reduction, relative to the proposal, in cumulative impacts of the types generally described in section 4.5.1.
Use of BPA resources to serve the contract, or to provide capacity in accord with any of the other alternatives analyzed, will contribute to the overall effects associated with BPA's system. However, these effects are beyond the scope of this EIS since the decision on the PacifiCorp contract is not a decision on FCRPS operations; these decisions are taking place in the SOR process. (See section 4.1.)
The Endangered Species Act of 1973, as amended (16 USC 1536), requires Federal agencies to ensure that their actions do not jeopardize endangered or threatened species or their critical habitats. In compliance with Section 7, BPA requested from the U.S. Fish and Wildlife Service (USFWS) a list of endangered and threatened plant and animal species in the affected environment. This information was provided by the appropriate USFWS Field Offices in Oregon, Washington, Idaho, Montana, Wyoming, Nevada, California, Arizona, New Mexico, Colorado, and Arizona, and is presented in Appendix B.
Consultations regarding the effects of Federal hydropower operations on endangered or threatened Columbia River salmon species are done on the annual operating plans prepared by BPA, the Corps of Engineers, and the U.S. Bureau of Reclamation. BPA's actions to implement power-related activities such as the capacity sale alternatives studied here will not conflict with the outcomes of such Endangered Species Act consultations and no specific consultation is therefore planned on these alternatives.