Federal Response:
A change in transmission congestion does not inherently reflect an overbuild of resources when these resources are needed to meet resource adequacy or power system reliability objectives.

The power system reliability analysis described under Step 2 of Section 3.7.3.1, Methods, estimated the effect of the alternatives on power system reliability (i.e., Loss of Load Probability) and Step 3 describes the identification of replacement resource portfolios, including the use of zero-carbon resources (e.g. solar) with lower capacity factors and variable output. As discussed under Step 4 of Section 3.7.3.1, Methods, the transmission congestion modeling evaluated the dispatch of resources and transmission use on an hourly-basis for a year under different hydro runoff conditions. Transmission flows with each alternatives resource replacement portfolios were compared against flows for the No Action Alternative.

While there may be an increase in transmission congestion hours or exports under certain flow regimes with replacement resource portfolios, the power reliability attributes of those portfolios and the ability to meet unserved load should be considered as well. Resources may be needed to meet power system reliability adequacy during a certain portion of the year. Transmission congestion modeling may reflect some congestion hours during other portions of the year when the resources may not be needed for power reliability purposes, but are available to displace resources with higher variable costs in different locations. Increases in transmission congestion hours reflect a potential increased cost to serve customer loads relative to an uncongested system.

bluefish counter response:
Although the CRSO is ambiguous, MO3's GridView and Powerflow results -- showing transmission congestion of electricity exports out of the region -- must be occurring when MO3's replacement is the Zero-Carbon portfolio. It is hard to imagine otherwise, how MO3's "conventional" portfolio could bring export transmission congestion, as it would dispatch only when electricity demand arises within the region.

With that potential caveat in mind, the following bluefish counter responses will assume the above to be the case, and it is MO3's Zero-Carbon Resource Replacement Portfolio (adding 583aMW of non-dispatchable solar power to the grid), that is causing the various transmission system congestions of the models.

Appendix H - Power and Transmission (page H-3-6)

Federal Response:
The co-lead agencies evaluated a range of spill levels to determine the various impacts across resources affected by CRS operations, maintenance and configuration. This included spill levels near 110% Total Dissolved Gas (TDG) up to 125% TDG. It is true that spill is typically lower in July and August than earlier in the juvenile fish passage season (April June). In MO3, spill for juvenile salmon passage reduces to surface passage (significantly lower spill levels) in August. In the Draft EIS, please see Exhibit 3 of Appendix J, Hydropower, top figure on page J-E3-3, which shows that generation at most lower Columbia River projects is slightly lower in MO3 than in the No Action Alternative (-90 to +40 aMW) in July; but, is 300-400 aMW higher in August.

bluefish counter response:
With the potential caveat of previous "bluefish counter response" in mind, let's reconsider the Powerflow excerpt toward the end of the above comment page by bluefish:

Appendix H - Bonneville Transmission System Reliability and Network Interconnections (page H-3-16)

. . .

This last sentence again supports the bluefish contention that the best way to compensate for hydropower lost under Remove Snake River Embankments would be to Reduce Exports, and make Market Purchases during Critical Water Years when conditions warrant. No replacement resources need to be built, according to the Seventh Power Plan, because existing natural gas plants will backup the grid when electricity demand and prices dictate (see Figure 3-19 several pages below).

Federal Response:
The co-lead agencies evaluated a range of spill levels to determine the various impacts across resources affected by CRS operations, maintenance and configuration. This included spill levels near 110% Total Dissolved Gas (TDG) up to 125% TDG. It is true that spill is typically lower in July and August than earlier in the juvenile fish passage season (April June). In MO3, spill for juvenile salmon passage reduces to surface passage (significantly lower spill levels) in August. In the Draft EIS, please see Exhibit 3 of Appendix J, Hydropower, top figure on page J-E3-3, which shows that generation at most lower Columbia River projects is slightly lower in MO3 than in the No Action Alternative (-90 to +40 aMW) in July; but, is 300-400 aMW higher in August.

Finally, the agencies that an alternative that includes breaching the four lower Snake River dams and spring spill operations to 125% TDG at all four lower Columbia River dams is reasonable given the unacceptable risks to public safety from such an alternative.

For power and transmission, MO3 and MO4, individually each caused large loss-of-load probability (LOLP) results (e.g. increased incidence of blackouts). Without major addition of new resources, MO3 would result in power shortages in about one in seven years. MO4 would produce power shortages in about one in every four years. If MO4 were implemented, in addition to breaching the four lower Snake River projects as called for in MO3, then the LOLP would be even higher, with power shortages potentially occurring almost every year. Additionally, if these MOs were combined, in 5% of the years, the power shortages would average close to 1,000 MW in early August when the region might be experiencing a heatwave with particularly high demand for air conditioning. 1,000 aMW is about the average amount of power consumed by Seattle City Light. As shown in Section 3.7, MO3 causes an increase in power reliability concerns in the winter and the summer. MO4 increases power reliability concerns in the summer. Thus, the combination has the largest impact during the summer. The cost of zero-carbon replacement resources for MO3 and MO4 individually are up to $1 billion/year. Resource replacements and associated transmission interconnections for the combination of MO3 and MO4 would be higher, though not likely as high as the sum of the two MOs individually. Assuming that the replacement resources consist largely of wind, solar, and batteries, this would require well over 50 square miles of solar power (more than two and a half times the size of Crater Lake), large areas of new wind generation, and unprecedented amounts of batteries (more batteries in the Northwest alone than the total projection of batteries expected in the entire US by 2023 per the Energy Information Administration).

In addition, the reduced generation capability under MO3, particularly throughout the summer, in combination with the impacts of the measures in MO4, and the uncertainty about the characteristics of replacement resources, would result in less capability to provide voltage support and dynamic stability for transmission system reliability than under MO3 or MO4 individually. Thus, combining MO4 with breaching the four lower Snake River projects, would produce unreasonable power and transmission reliability impacts, and it is highly speculative that replacement resources could be sited, permitted and built to address these impacts. This potential alternative has not been evaluated for direct, indirect and cumulative effects to other resources. Thus, an alternative combining juvenile fish passage spill up to 125% and breaching the four lower Snake River dams is unreasonable, and thus was not proposed as an alternative.

Hilarious -- bluefish counter response:
The Fed's must have made a typographical error in their second paragraph, "reasonable given the unacceptable..." but that is not the most hilarious part of their response. Somehow, maybe purposefully, the CRSO respondents became confused, and responded as though the bluefish suggestion was to Increase spill to 125% TDG.

Repeating bluefish from immediately above:
This is yet another reason for running a complete analysis of MO3 WITHOUT INCREASED SPILL...

Then in the next paragraph, the already confused CRSO respondents, add further to their state of confusion, responding as though the bluefish suggestion was to combine Remove Snake River Embankments on top of all of Multiple Objective 4 (MO4). Quite obviously, that was most certainly NOT the bluefish suggestion, but that does not stop them from acting as though it was.

Deviously, that is one way to set aside a good idea, act like you did not hear the suggestion.

The EIS set forth eight objectives which, in tandem with the Purpose and Need Statement, establish the framework for evaluating the ability of an alternative to satisfy the co-leads numerous legal obligations. The Preferred Alternative is predicted to benefit juvenile and adult anadromous salmonids (two of the objectives), and also meets most of all the other objectives of the study for resident fish, lamprey, hydropower generation, water management, and water supply and greenhouse gas emissions. It minimizing adverse impacts to communities and the economy. The Preferred Alternative is likely to satisfy multiple complex and at times conflicting legal requirements for a complex system.

Federal Response:
Appendix J, Figure 3-5 in the Draft EIS, shows the critical-year generation for MO1. The comparable graph showing monthly generation changes under critical water conditions (1937 water) for MO3 is Figure 3-9. In Figure 3-9, there is a slight net increase in generation in January as the increase in generation at Grand Coulee, the lower Columbia River, and other projects exceeds the lost generation from the four lower Snake River dams. However, the generation change for all three winter months on average is a loss.

bluefish counter response:
It is good that the CRSO respondents agree with a direct excerpt of the CRSO Draft, but the bold emphasis (in the Appendix J excerpt) is meant to draw attention to MO3's Increase Spill to 120% TDG, and the Reliability Events that this brings, especially in June (see Figure 4-4 below).

Appendix J - Hydropower MO3 Change from NAA (page J-4-7)

Also worth noting here, is that MO3's Reduce Summer Spill is very beneficial to the power grid. Ending summer spill on July 31 will greatly reduce LOLP Reliability Events that would otherwise occur in August (see Figure 3-9 above).

Executive Summary: Multiple Objective Alternative 3 (MO3) (page 29)
Reduced spill levels would allow for increased hydro-power production during August when low numbers of juvenile fish are typically present.
. . .
Fish modeling for MO3 predicts the highest benefits among all of the alternatives for ESA-listed salmon in the Snake River and could, in the long-term, provide additional riverine type recreational opportunities.

The biological benefits of increased spill are discussed in the Schaller et al. report, which underlies the CSS modeling promoting the "spill experiment". Importantly, that same report shows Remove Snake River Embankments to be, by far, the best action that we can take to recover Idaho salmon and steelhead populations. Alongside that hotly debated action, Increase Spill to 120% TDG may be unnecessary, and that is a strategy to which bluefish is striving to bring attention.

Federal Response:
The commenter is correct that the generation loss in May and June from losing generation at the four lower Snake River dams is roughly comparable to the loss in generation due to increased spill and small changes in flows at the four lower Columbia River projects.

bluefish counter response:
CRSO respondents are somehow missing the point: Increase Spill to 120% TDG adds significantly to the Loss of Load Probability (LOLP) under MO3. Looking at MO3 without this increase of spill, is worth the effort of analysis.

For best modeling results, the Council's Redeveloped GENESYS should be put to use.

bluefish counter response:
To paraphrase the above excerpt from Appendix H 3.2.1 Powerflow Results:

Appendix H - Bonneville Transmission System Reliability and Network Interconnections (page H-3-16)

Setting us up for what is yet to come, we repeat a sentence of the last paragraph (above):

Appendix H - Bonneville Transmission System Reliability and Network Interconnections (page H-3-26)

Federal Response:
As discussed in the Bonneville Transmission System Reliability and Operations subsection in Section 3.7.3.5 of the Draft EIS and Section 3.2.2 of Appendix H, prior to evaluating the impacts of potential breach of Ice Harbor Dam, Bonneville had identified the need for a transmission reinforcement project just beyond the 10-year planning horizon (2018-2028) to maintain reliable load service to accommodate load growth, to the Tri-Cities area and to support transmission operations and maintenance. From a transmission rates perspective, this means that Bonneville would not expect to see the impact of such a project within the 10-year planning horizon. The base need for the project would arise independent of removal of the generation at Ice Harbor. However, the timing of the reinforcement is very dependent on when Ice Harbor might be breached and would be needed immediately. As such, the transmission analysis considered the speed up of the timing for the need for the reinforcement project as a result of breaching the four lower Snake River dams evaluated under MO3, by including the costs of the project starting at the time the generation from Ice Harbor would be removed from the system. This would allow time for environmental compliance, permitting and construction to occur.

The EIS analyzed the cumulative transmission rate pressure changes relative to the No Action Alternative through 2028 for all of the alternatives. Under the No Action Alternative, the Tri-Cities area reinforcement would not be needed within this 10-year time frame and was, therefore, not reflected in the baseline for this time period. The transmission rate pressure relative to the No Action Alternative for MO3 did reflect these reinforcement costs as MO3 would require the reinforcement project under both resource replacement portfolios during the 10-year transmission rate pressure analysis timeframe. Section 4.2.1.1, Revenue Requirement, of Appendix H contains a discussion of the transmission capital cost assumptions, including the timing and direct costs.

As discussed in Section 3.7.3.5, Potential Replacement Resources and Associated Costs, under the least-cost replacement generation portfolio, returning Loss of Load Probability to the No Action Alternative level could be accomplished with approximately 1,120 MW of combined cycle natural gas turbines located in northeastern Oregon in a base case without additional coal closures. As a result, the transmission analysis identified interconnection costs associated with the identified resource replacement, which was assumed to be located in northeastern Oregon near McNary due to the location of existing infrastructure.

bluefish counter response:
Foreshadowing a contradiction of the Federal Responses to bluefish (see second to last "Click for Response" below), let's repeat what they admit to here:

The base need for the project would arise independent of removal of the generation at Ice Harbor.

Did you get that? Transmission upgrades are needed in the Tri-City area regardless of the implementation of Remove Snake River Embankments.

Federal Response:
As discussed in Section 3.7.3.5, Potential Replacement Resources and Associated Costs, under the least-cost replacement generation portfolio, returning Loss of Load Probability to the No Action Alternative level could be accomplished with approximately 1,120 MW of combined cycle natural gas turbines located in northeastern Oregon in a base case without additional coal closures. As a result, the transmission analysis identified interconnection costs associated with the identified resource replacement, which was assumed to be located in northeastern Oregon near McNary due to the location of existing infrastructure.

The Northwest Power and Conservation Council (Council) ran a study of the loss of a major non-carbon producing resource, but this study did not look at breaching the four lower Snake River dams, in the Seventh Power Plan using their resource portfolio model. The lost-resource in the Council's study had a smaller energy and much smaller capacity attribute compared to the four lower Snake River dams. Further, the Council's load forecast at the time of the Seventh Power Plan was lower than the more recent load forecast used in the EIS. The EIS did not use the Council's resource portfolio model. The EIS instead used the Council's GENESYS model, Council data including that of the 2022 Resource Adequacy Assessment, and the Council's resource adequacy metric and standard and only proposed replacement resource portfolios if that standard was not met. See Section 3.7.3.1, Step 3: Determine Need for Potential Replacement Resources and Associated Costs, at page 3- 821; and Appendix H, Power and Transmission, at Section 2.2 in the Draft EIS.

bluefish counter response:
The Council scenario "Loss of Major non-Greenhouse Gas Emitting Resource" began it's life as "Lower Snake River Dam Breach" and corresponds to removing 250 MW every third year until 1000 MW has been removed.

Seventh Power Plan: Resource Strategy (page 3-12)

As stated above, "The EIS did not use the Counci'ls resource portfolio" and thereby did not include the possiblity of reducing 4,200aMW of exports as the Sixth and Seventh Power Plans did, and found them to be major components of their "Least Cost Resource Portfolios". Notably, the Seventh Power Plan did not see the need for new natural gas-fired resources until far out in their planning horizon (see Figure 3-14 below).

Federal Response:
The statements in this comment regarding transmission system reliability and operations and the location of natural gas resources is consistent with the Bonneville Transmission System Reliability and Operations subsections of Section 3.7.3.3, Section 3.7.3.5, and Section 3.7.3.6 of the Draft EIS and Section 3.2.4 of Appendix H.

bluefish counter response:
It's a good thing that CRSO respondents find that a direct excerpt from the CRSO Draft is consistent with itself. Siting 680 MW CCCT near McNary Dam would provide voltage and dynamic support for the transmission system.

From the power system side of things, it seems the best reason the CRSO has for keeping the LSR dams, is its ability to ramp quickly to 2000 MW in February, less within the salmon migration seasons, and averaging around 1500 aMW.

While the CRSO presses the importance of LSR dam's "Historical Sustained Ramping", the EIS downplays the $181 million value that 500MW of natural gas fired turbines would bring as a Resource Replacement Portfolio (680MW / 500MW x $181 million = $246 million anually for a 680 MW CCCT Resource Replacement Portfolio).

Federal Response:
As explained in the draft EIS, Section 3.7.3.1, Base Case Methodology and Cost Sensitivities Analysis, the analysis evaluates the power impacts of the Multiple Objective (MO) Alternatives on regional power system reliability, as measured through loss of load probability (LOLP). The ensuing assessment of the transmission system evaluated the feasibility of whether the identified portfolio of replacement resources might reasonably be able to reliably integrate into the transmission system. As such, the impacts to the transmission system and any associated mitigation was based on the preceding power system reliability steps.

MO3 includes the removal of generation from the four lower Snake River projects. Bonneville is aware of the suggestions that the existing stations that currently integrate the output from the four lower Snake River projects could be used to accommodate synchronous condensers.

The EIS analysis and modeling considered that additional static devices, such as reactors or capacitors, might be added or be used to modify the existing reactive equipment at these sites. The assessment found that removal of generation from these points on the transmission system would negate the need for supplemental voltage support from devices such as synchronous condensers at these locations. The analysis concluded that such modification would not be needed at these sites in the event of complete removal of the generation from the four lower Snake River projects.

Hooray! -- bluefish counter response:
Let's hear that again:

Removal of (LSR) generation from these points on the transmission system would negate the need for supplemental voltage support from devices such as synchronous condensers at these locations.

Surprisingly, the next Federal Response (below) contradicts this one.

Federal Response:
The commenter suggests that the EIS inappropriately cites Ice Harbor as being critical to main grid stability and voltage support. The EIS did not assert that the transmission system need for the Ice Harbor resource was to support the transmission system in general for the export to California lines. Rather the EIS cites that Ice Harbor is uniquely situated in the transmission network to provide active load support to loads within the Tri-Cities area, in Washington (see Draft EIS Section 3.7.3.5, Bonneville Transmission System Reliability and Operations). As such Ice Harbor is a critical resource to the transmission system.

The EIS also considers that if Ice Harbor is breached and generation is completely removed under MO3 there would be an additional need to provide another transmission source to serve Tri-Cities load immediately.

Contradiction -- bluefish counter response:
This response contradicts three earlier Federal Responses (above):

"Removal of (LSR) generation from these points on the transmission system would negate the need for supplemental voltage support from devices such as synchronous condensers at these locations."

"MO3, which includes the breach of LSR dams, would be the only alternative where the studies indicated a need for system reinforcement."

"The base need for the (transmission reinforcement) project would arise independent of removal of the generation at Ice Harbor."

When the left hand does not know what the right hand is doing, efforts to deceive are easier to see.

CRSO Executive Summary
The loss of hydropower generation at Ice Harbor would require that a transmission reinforcement project be in place prior to breaching of the dams. The transmission reinforcement project is estimated to cost about $94 million.

Federal Response:
The draft EIS describes, in the referenced table in Section 4.1.1.1 of Appendix H, that customer loads were calculated after updating Tier 1 resource generation under each alternative. If the amount of firm generation available from the Federal Columbia River Power System decreases, then the amount of Tier 1 power that customers are entitled to purchase from Bonneville must decrease. Customers then have the choice of either purchasing Tier 2 power from Bonneville or acquiring power elsewhere. Thus, the level of loads presented in the table are driven by the changes in hydropower generation and generation from replacement resources.

If the replacement resources are not financed by Bonneville (i.e., the region finances scenarios) then no replacement resource generation was included, reducing the loads relative to the No Action Alternative. When Bonneville finances the portfolio, the power analysis finds that the zero-carbon portfolio does not replace all of the hydropower generation lost under Multiple Objective (MO) Alternative 3 (which includes breaching of the four lower Snake River dams); therefore, Tier 1 loads decrease relative to the No Action Alternative. However, with a least-cost portfolio of natural gas, public customer loads increased relative to the No Action Alternative due to the increase in natural gas generation needed to maintain power system reliability.

Comment 32180-34 (by the same commenter) discusses the Northwest Power and Conservation Council (Council) study of the Planned Loss of a Major non-GHG Emitting Resource. This study is different in that the attributes of the Council's generic lost resource are not comparable to those of the four lower Snake River dams. For more discussion on this topic, please refer to that comment and response.

bluefish counter response:
The Council scenario "Loss of Major non-Greenhouse Gas Emitting Resource" The Seventh Power Plan's "Planned Loss of Major non-Greenhouse Gas Emitting Resource" began it's life as "Lower Snake River Dam Breach" and corresponds to removing 250 MW every third year until 1000 MW has been removed (see "Click for Response" four above).

What CRSO respondents may be alluding to, is that the "Historic Sustained Peaking" is not modeled in the Seventh Power Plan, nor could it have been as this is a brand new metric, invented expressly for the CRSO EIS.

The comment suggests that Bonneville run an analysis of whether loads can be met by reducing exports and not purchasing replacement resources. The LOLP modeling does not include export loads, and all regional resources are used to meet regional loads. In the EIS, the LOLP was first assessed without replacement resources. The results are presented in Section 3.7.3.5, Effects on Power System Reliability at page 3-905 in the draft EIS. Without replacement resources, the LOLP level more than doubles to 14%. See Section 3.7.3.5, Effects on Power System Reliability, at 3-903 and Appendix H, Table 2-1 in the draft EIS. The Council's 7th Power Plan had an older load forecast and other differences from the EIS.

bluefish counter response:
The old GENESYS model includes exports to South California in Light Load and High Load Hours.

"The ability to simulate the sale of surplus energy and/or capacity from the NW was disabled many years ago in the classic GENESYS (the redeveloped GENESYS does model those). This was done because the RAAC wanted to focus on the adequacy part of the model and so therefore removed all loads and resources from out of region bubbles except resources used to serve firm imports or to provide spot market supplies."

-- email from NW Council, Power Division staff, 9/15/20

The findings of the EIS regarding surplus sales under MO3 are consistent with the statement in the comment. Due to the reduction in hydropower, secondary sales decrease, this in turn decreases revenue (Table 4-9 of Appendix H in the draft EIS).

Federal Response:
The figure that the commenter cites, Appendix H Figure 5-4, displays the data for Multiple Objective (MO) Alternative 2, but was inadvertently mislabeled in the draft EIS. Figure 5-2 is MO1 and Figure 5-3 is MO3 and Figure 5-4 is MO2, not MO3 without replacement resources as suggested in the comment. Figure 3-186 in Section 3.7 of the draft EIS, shows the correct figure for MO3. The Tables in Appendix H, Chapter 5 correctly show rate increases for MO3 as noted in the comment. The error in the graphs in Appendix H will be corrected in the final EIS.

Regarding Table 6-1, "/1" is a table note and should be superscript. This is corrected in the Final EIS where it is Exhibit 1.

bluefish counter response:

Actually, the Tables at the end of Appendix H have been updated from the Draft, and the Draft Figure 5-4 is not representative of MO2 as the Federal Respondents have asserted here. These are all details that we can set aside and get to the main point.

Retail Rate Pressure is reduced following Remove Snake River Embankments, a fact that the co-lead agencies have worked to conceal.

Asking for clarity, bluefish was not the only commenter to ask that that Spill to 120% TDG not be placed on top of Remove Snake River Embankments. Further complicating the results, End Summer Spill rounds out the three main components of Multiple Objective 3 (MO3). Was there really some point to blending these three together? Personally, I can see no benefit other than obfuscation, which benefits only the "Save Our Dams" community.

Please contact bluefish if you can think of some other reason for this blending. The Federal Respondents provided no reasoning when the State of Washington raised this same concern. Governor Jay Inslee asked for clarity, but this concern was flatly rejected.

State of Washington, Office of the Governor, Jay Inslee (Appendix T - Public Comments page T-1068)
As noted in our February 2017 scoping comments, Washington envisioned a CRSO EIS that is more visionary and provides more context for informed policy making than is afforded by the draft EIS. We have the following concerns, which build on concerns Washingtons cooperating agencies have conveyed throughout the CRSO NEPA process:

• The draft EIS does not contain a restoration bookend alternative that optimizes salmon and steelhead survival. Multiple Objective Alternative 3 (MO3) and Multiple Objective Alternative 4 (MO4) include powerful new fish recovery actions (breaching and higher spill, respectively), but they also include new actions that may harm salmon survival. The lack of a bookend fish-friendly alternative compromises the ability of the region to place the Preferred Alternative in context.

• The draft EIS does not furnish a basis that allows the reader to analyze the effect of various individual components of the multiple objective alternatives, which makes it impossible to determine how much an individual action helps or hinders achieving the documents various goals.

• The goal the draft EIS is working to meet for salmon and steelhead recovery is vague. It appears to be aiming for improvement well short of the State of Washingtons healthy, harvestable goal (see Washington scoping comments, footnote 1 for more background), which is compatible with the Northwest Power and Conservation Council's goal of a 2-6% smolt-to-adult return ratio, with an average of 4%, and provisional population goals developed by the collaborative Columbia Basin Partnership.

• . . .

Federal Response to Washington Governor Inslee:
The co-lead Agencies are required to evaluate a reasonable range of alternatives in the EIS. However, when there are potentially a very large number of alternatives, only a reasonable number of examples, covering the full spectrum of alternatives, must be analyzed and compared in the EIS. Alternatives for this EIS were developed from measures identified during public scoping, regional forums with scientists and technical experts from cooperating agencies (including Washington), and expert opinion from within the co-lead agencies and in the literature. These alternatives represent a reasonable range of alternatives for the maintenance and operation of the CRS.

It should be noted that the 2-6% Smolt-to-Adult return (SAR) target referenced in this comment refers to the Northwest Power and Conservation Council (Council) target for broad-sense recovery and is separate and distinct from the obligations of any single entity or in this case a requirement to be met solely by the co-lead agencies.

Just as the Council's fish and wildlife program encompasses both federal and non-federal stakeholders in the Columbia Basin, the Council's recovery goals are shared by many parties. Based on the Preferred Alternative analysis, it will make a substantial contribution, but the Council's broad sense recovery goals are beyond the scope of this EIS, which focuses on the effects associated with the operation and maintenance of the 14 CRS projects.

The co-lead agencies are legally obligated to operate and maintain the CRS to meet multiple statutory purposes. They are also required to ensure operation of the CRS complies with other laws.

bluefish interjects: Are the co-lead agencies "legally obligated" to produce a legitimate NEPA document?

The Governor of Washington is asking for a Final document that "provides more context for informed policy making than is afforded by the draft EIS." The co-lead agencies do not oblige.

Federal Response to Gov. Inslee (continues)
Under the ESA, in particular, the operation of the CRS may not appreciably reduce the likelihood of listed species survival and recovery, or adversely modify or destroy designated critical habitat. The ESA does not, however, require the co-lead agencies to take affirmative actions to recover ESA-listed species as that is a broader goal with shared responsibility.

Based on the fish analysis in Section 7.7.4, the co-lead agencies anticipate that the Preferred Alternative would provide substantial benefits to ESA-listed species and is not expected to diminish the likelihood of recovery. The effects of delayed mortality are discussed throughout the EIS analysis for each alternative and current high quality data and the best available scientific information was used for this analysis.

Based on analysis by the CSS, SARs associated with population declines (SARs of less than 1%) have the potential to be greatly reduced under the Preferred Alternative, and on average, SARs are expected to be well above 2.0% for Snake River spring Chinook salmon and steelhead.

The NMFS COMPASS and Life Cycle models predict higher levels of risk associated with increased spill levels in the absence of offsets from decreased latent mortality. The Preferred Alternative will be implemented using a robust monitoring plan to help narrow the uncertainty between the two models and to determine how effective increased spill can be towards increasing salmon and steelhead returns to the Columbia Basin.

. . .

Regarding Southern Resident Killer Whales (SRKW), the population dynamics of the SRKW are complicated, and there is no one factor that contributes to the overall success of this species; however, the co-lead agencies agree that the quantity and quality of prey is one of the limiting factors identified by NMFS in recovery of SRKWs.

Based on the fish analysis in Section 7.7.4, the co-lead agencies anticipate that the Preferred Alternative would provide substantial benefits to ESA-listed species and is not expected to diminish the likelihood of recovery. Additionally, Section 7.7.8 states impacts to Southern Resident killer whales would be negligible.
. . .

Had the co-lead agencies taken Gov. Inslee's plea to heart, the following map would have been presented in the Final document. If you have some means of providing this map to Gov. Inslee and/or his staff, please do so at your earliest convenience.

Appendix H - Figure 5-4 modified to include only Remove Snake River Embankments

Q: How did bluefish compute the values for this map?

A: Using the updated tables at the end of Appendix H, along with a corrected Table 3-312 above, linear interpolation of the available data yields Retail Rate Pressure of each county.

To illustrate this process of linear interpolation, let's use Benton County, Washington.

Appendix H - Exhibit 1 Residential Retail Rate by County

• Assume that retail rate impacts are half of Bonneville's rate reductions (15.1% reduction becomes an 7.5% reduction).

• For Benton County, Exhibit 1 has No Action Alternative at $8.38/MWh, and MO3 brings a 4% increase (to $8.72/MWh).

• For Benton County, a 7.5% reduction from No Action Alternative (NAA) of $8.38 yields a $7.75 price.

• For Benton County, $7.75 would be the price of MO3 before adding combined cycle combustion turbines (CCCT) as mitigation for the loss of hydropower. Exhibit 1 reports $8.72 as the price of M03 afterward. The difference is $0.97/MWh.

• The important point to consider is that Remove Snake River Embankment is 680 MW / 1120 MW of the total difference that is given in Appendix H, Exhibit 1. Then proceed.

• For Benton County, a $0.97 x 680 MW / 1120 MW = $0.58.

• For Benton County, add $0.58 to the rate calculated for MO3 before mitigation of $7.75 to arrive at $8.33/MWh.

• For Benton County, conclude that a rate of $8.33 is a 0.5% reduction from "Exhibit 1" (above Table) reporting NAA rate of $8.38 per MWh.

Proceeding likewise for all the counties with data listed in Appendix H, Exhibit 1 brings us the map above of rate changes throughout the Pacific Northwest. An Excel spreadsheet of these calculations is available here.