                       WYOMING STATE IMPLEMENTATION PLAN
                                       
                                 Regional Haze
                                       
                                       
          Addressing Regional Haze Requirements for Wyoming Mandatory
                 Federal Class I Areas Under 40 CFR 51.309(g)
                                       
                           Grand Teton National Park
                           Yellowstone National Park
                              Bridger Wilderness
                            Fitzpatrick Wilderness
                           North Absaroka Wilderness
                               Teton Wilderness
                              Washakie Wilderness
                                       
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                               Table of Contents
                                       
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Chapter 7. Reasonable Progress Goals.......................................................................

7.1 Overview...................................................................................................................
7.2 Process for Establishing Reasonable Progress Goals...............................................
7.3 Four Factor Analysis Performed for Wyoming Sources...........................................
      7.3.1 Detailed Description of the Four Factors...................................................
      7.3.2 Source Selection Process for Four Factor Analysis...................................
      7.3.3 PacifiCorp Dave Johnston Electric Generating Station.............................
      7.3.4 Mountain Cement Company, Laramie Plant..............................................
      7.3.5 Oil and Gas Exploration and Production Field Operations........................
      7.3.6 PacifiCorp Jim Bridger Electric Generating Station..........................
7.4 309 SIP and 309(g)....................................................................................................
7.5 Setting Reasonable Progress Goals...........................................................................
7.6 Demonstration That the RPGs for 20 Percent Best and Worst Days are
Reasonable.......................................................................................................................

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List of Tables

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Table 7.3.3-1. Estimated Costs of Potential Emission Control Devices for Two Boilers at the Dave Johnston Electric Generation Station...............................................
Table 7.3.3-2. Estimated Energy and Non-Air Environmental Impacts of Potential Emission Control Devices for Two Boilers at the Dave Johnston Electric Generating Station.........................................................................................................
Table 7.3.4-1. Estimated Costs of Potential Emission Control Devices for One Cement Kiln at the Mountain Cement Company, Laramie Plant........................................
Table 7.3.4-2. Estimated Energy and Non-Air Environmental Impacts of Potential Emission Control Devices for Kiln #2 at the Mountain Cement Company, Laramie Plant.............................................................................................................
Table 7.3.5-1. Estimated Costs for Oil and Gas Exploration and Production Equipment...
Table 7.3.6-1. Updated Costs of Emission Control Technologies for the Jim Bridger Electric Generating Station.......................................................
Table 7.3.6-2. Voluntary Visibility Enhancing Emissions Limits for the Jim Bridger Electric Generating Station.......................................................
Table 7.3.6-3. Incremental Costs of Voluntary Visibility Enhancing Emissions Limits Compared to SNCR and SCR for the Jim Bridger Electric Generating Station.......................................................

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Table 8.3.3-1. 	Enforceable Monthly Block NOx and SO2 Emissions Limits Imposed on the Jim Bridger Electric Generating Station, Effective January 1, 2022.

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                                   CHAPTER 7
                           REASONABLE PROGRESS GOALS
                                       
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7.3 Four Factor Analysis Performed for Wyoming Sources

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7.3.6 PacifiCorp Jim Bridger Electric Generating Station
On January 30, 2014, EPA published a final Regional Haze Rule (79 FR 5032) that approved the NOX portion of Wyoming's State Implementation Plan (SIP) requiring controls of NOX emissions from the Jim Bridger Power Plant, Units 1-4.  For NOX controls, EPA determined that Wyoming's selection of NOX controls of low NOX burners (LNB) and separated over fired air (SOFA) with emission limits of 0.26 lb/MMBtu (30-day rolling average) qualified for BART controls.  Additionally, EPA approved Wyoming's requirement that LNB/SOFA plus selective catalytic reduction (SCR) be installed at Jim Bridger Units 1-4 as part of the State's Reasonable Progress Long Term Strategy (RP/LTS). The resulting Wyoming SIP required, as part of its RP/LTS, installation of SCR controls on all four Jim Bridger Units in a phased approach with NOX emission limits of 0.07 lb/MMBtu (30-day rolling average) becoming effective upon SCR installation. 
Units 3 and 4 each have LNB/SOFA + SCR installed, with SCR installation being completed by the required 2015 and 2016 deadlines. Each unit is required to maintain an emission limit of 0.07 lb/MMBtu (30-day rolling average). Units 1 and 2 each have LNB/SOFA installed and each unit is required to maintain an emission limit of 0.26 lb/MMBtu (30-day rolling average). The LNB/SOFA installed on Units 1 and 2, along with their respective 30-day rolling average NOX limits are hereafter referred to as the "Current Unit 1-2 NOX Controls". 
Due to the significant costs of installing SCR on Units 1 and 2, and the potential impact of those costs to PacifiCorp's customers, PacifiCorp reassessed its compliance with the Regional Haze Rule and developed an alternative regional haze compliance strategy, which PacifiCorp stated was more cost effective, had less environmental impacts, and resulted in better visibility than SCR or selective non-catalytic reduction (SNCR) installation on Units 1 and 2.  That alternative regional haze compliance strategy (referred to as the "Reasonable Progress Reassessment" or "RP Reassessment") for the Jim Bridger Power Plant included a four-factor "reasonable progress" analysis, and proposed new, reduced plant-wide month-by-month, emissions limits for the two principal haze-causing pollutants, NOX and SO2. In addition to proposing new monthly average NOX and SO2 emission limits, PacifiCorp also proposed an annual total emissions cap of NOX and SO2 for the Jim Bridger Units 1-4 boilers. 
Upon reviewing PacifiCorp's RP Reassessment application, and relevant related information, the State of Wyoming opted to reconsider its previous requirement that LNB/SOFA + SCR be installed at Jim Bridger Units 1 and 2 as part of the State's RP/LTS. Pursuant to 42 U.S.C. § 7410(l) and 40 CFR 51.308(h), the State of Wyoming may determine the adequacy of, and revise, its existing implementation plan. While PacifiCorp provided a four-factor reasonable progress analysis that included new proposed limits for both NOX and SO2, the State of Wyoming considered it appropriate to re-balance and reconsider its RP/LTS determination and complete a four factor reasonable progress analysis on a NOX-only basis. Wyoming also considered it appropriate to complete its NOX analysis by examining SCR, SNCR, and the Current Unit 1-2 NOX Controls, while PacifiCorp's proposed limits included in the RP Reassessment were considered as supplemental information.
    Cost 
EPA's 2014 final Regional Haze Rule, which approved portions of Wyoming's implementation plan, evaluated the costs of compliance for three control technologies: LNB/SOFA; LNB/SOFA + SNCR; and LNB/SOFA + SCR. See 79 FR 5032, 5048 (Jan. 30, 2014). EPA found that the incremental costs effectiveness ($7,477/ton on Unit 1 and $8,968/ton on Unit 2) for SCR was "on the high end" of what was reasonable in other federal plans. EPA acknowledged that its approval of Wyoming's determination to require SCR on Units 1 and 2 was a "close call"; thus EPA explained that "deference to the state [was] appropriate" in approving the SCR installation requirement. 79 Fed. Reg. at 5048. 
In its RP Reassessment application, PacifiCorp provided updated capital costs, annual costs, and the cost effectiveness for three potential regional haze control strategies at the Jim Bridger Power Plant. The three potential regional haze control strategies considered were: SCR installed on Units 1 and 2; SNCR installed on Units 1 and 2; and new NOX and SO2 operational limits applied to Units 1-4. As stated above, the State of Wyoming considered the costs of SCR, SNCR, and the Current Unit 1-2 NOX Controls as part of its reconsidered RP/LTS.
In PacifiCorp's updated costs analysis, the additional costs that would be required to install SCR and SNCR were evaluated under 20 year and 30 year amortization periods, respectively. The capital costs under any amortization schedule remain the same. In May of 2016, the EPA finalized revisions to the Air Pollution Control Cost Manual, which changed the amortization period for SCR from 20 years to 30 years; while the amortization period for SNCR remained at 20 years. Section 7.3.1 above acknowledges that it is appropriate to evaluate and compare costs over different amortization periods when the expected life of the source is less than the expected life of the emission control device. For this evaluation, the expected life of the source is less than the expected life of either control device; while the expected life for SCR is 30 years, and the expected life of SNCR is 20 years. The annual costs and cost effectiveness estimates in this analysis appropriately reflect these varying life expectancies. 
The estimated capital cost for SCR installation on Units 1 and 2, in addition to the LNB/SOFA already installed is $297,252,000, with an annual cost of $29,431,000. The estimated capital cost for SNCR installation on Units 1 and 2, in addition to the LNB/SOFA already installed on Units 1 and 2 is $47,472,000, with an annual cost of $10,734,000.         
The Current Unit 1-2 NOX Controls were installed in 2010 and 2005 for Units 1 and 2, respectively. Based on information provided by PacifiCorp, the capital cost for NOX control installation on Unit 1 was $8,410,000, with an annual cost of $794,000. The capital cost for NOX control installation on Unit 2 was $7,986,000, with an annual cost of $754,000. While this analysis does not rely on NOX reductions related to controls installed on Units 3 and 4, it's relevant to note that PacifiCorp's capital costs incurred for NOX control installation on Units 3 and 4 (LNB/SOFA + SCR) were $147,963,000 and $162,996,000, respectively. 
Table 7.3.6.1 below provides a summary of the actual costs of the Current Unit 1-2 NOX Controls (LNB/SOFA) compared to the costs of LNB/SOFA + SNCR and LNB/SOFA +SCR.    As can be seen in Table 7.3.6-1, SCR installation would cost hundreds of millions more than the costs already incurred for the Current Unit 1-2 NOX Controls, while SNCR would cost tens of millions more. 
Table 7.3.6-1. 	Updated Costs of Emission Control Technologies for the Jim Bridger Electric Generating Station



                                Cost Estimates
                                    Unit ID
                              Control Technology
                            Control Efficiency (%)
                               Capital Cost ($)
                             Annual Cost ($/year)
                                     JB1,2
                                   LNB/SOFA*
                                      53
                                  16,396,000
                                   1,548,000
                                     JB1,2
                                LNB/SOFA + SNCR
                                      63
                                  47,472,000
                                  10,734,000
                                     JB1,2
                                LNB/SOFA + SCR
                                      87
                                  297,252,000
                                  29,431,000
      * Represents the Unit 1-2 Current NOx Controls and actual costs already incurred.

Considering the substantial difference between the cost to install SCR or SNCR on Units 1 and 2 compared to the costs of the Current Unit 1-2 NOX Controls, particularly given the small incremental visibility differences, the cost analysis strongly favors the Current Unit 1-2 NOX Controls.  This analysis is consistent with other EPA regional haze actions. See e.g., Arkansas (80 Fed. Reg. 18,944, 18,975) ("Although the average and incremental cost-effectiveness of LNB/SOFA + SCR at Units 1 and 2 is still within the range of what we consider to be cost-effective, we believe the incremental visibility benefit over LNB/SOFA + SNCR of up to 0.069 dv at a single Class I area is relatively small considering the incremental cost-effectiveness of $6,717 per ton of NOX removed for Unit 1 and $5,736 per ton of NOX removed for Unit 2. Therefore, we are proposing to determine that NOX BART for White Bluff Units 1 and 2 is an emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average based on the installation and operation of LNB/SOFA."); Nevada, (77 Fed. Reg. 21,896, 21,898,) ("In its BART determination of RGGS, NDEP considered several control technologies, including Selective Catalytic Reduction (SCR), SNCR and ROFA with Rotamix. NDEP concluded that SCR would result in a very small incremental improvement of visibility over other technologies, which did not justify the incremental cost of installing and operating SCR. The results of our own analysis of the incremental visibility improvement and cost for SCR differ from NDEP's analysis in certain respects, but support NDEP's decision to establish a NOX BART emission limit that could be achieved with ROFA and Rotamix (or SNCR) rather than requiring an emission limit consistent with SCR technology.").
    Time Necessary for Compliance 
The Wyoming Regional Haze 309(g) SIP requires SCR installation on Jim Bridger Unit 1 by the end of 2022, and on Unit 2 by the end of 2021. If SNCR installation was required, the compliance timelines would match the SCR timeline. The Current Unit 1-2 NOX Controls were installed in 2010 and 2005 for Units 1 and 2, respectively.
    Energy and Non-Air Quality Impacts 
EPA's 2007 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program ("2007 RPG Guidance") provides information on setting Reasonable Progress Goals and determining the measures necessary to meet the goals. Section 5.3 of the 2007 RPG Guidance suggests that some of the "non-air environmental impacts" that States may consider are "the waste stream that may be generated by a particular control technology, and/or other resource consumptions rates such as water, water supply, and waste water disposal." None of the control technologies considered in this analysis consistently produce solid or liquid wastestreams, however SCR periodically produces solid waste when the catalyst is changed. PacifiCorp's application states that one layer of catalyst on each installed SCR would need to be replaced once every two years. In previous analyses, the State of Wyoming has found that LNB/SOFA technologies need roughly 1/6th of the electricity required by SNCR, and 1/150 of the electricity required by SCR. 

The installation of SCR at Units 1 and 2 would result in the additional storage and use of ammonia (a hazardous substance) and the use of approximately 10.4 MW of electrical energy. Likewise, the installation of SNCR on Units 1 and 2 would require the storage and use of urea. No additional negative non-air environmental impacts are anticipated based on the Current Unit 1-2 NOX Controls.
   
    Remaining Useful Life 
   
Section 7.3.1 above provides guidance on evaluating annual costs of emission controls when the expected life of the source is less than the expected life of the emission control device, which is the case here. For this evaluation, the expected life of the source is to the end of remaining useful life; while the expected life for SCR is 30 years, and the expected life of SNCR is 20 years. 

    Visibility Impacts
   
Although visibility is not a specific statutory factor, EPA has stated that States can consider visibility as part of a "reasonable progress" determination.  See 81 FR 296, 310-311. EPA has previously analyzed visibility improvement as part of its reasonable progress determinations for Wyoming.  See 79 FR 5032, 5051. 

EPA's 2014 final Regional Haze Rule presented the visibility impacts of the control technologies that were evaluated for costs of compliance: LNB/SOFA; LNB/SOFA + SNCR; and LNB/SOFA + SCR. See 79 FR 5032, 5048). In its analysis EPA, determined that that the unit-specific visibility benefits for LNB/SOFA+SCR installation on Units 1 and 2 were "modest" (0.27 to 0.37 deciviews). EPA also found that the incremental visibility improvement of installation of LNB/SOFA was .10 to .14 deciviews for Unit 1, and .11 to .15 deciviews for Unit 2. See 79 FR 5032, 5048 (Table 19). The incremental improvement of SNCR over LNB/SOFA was found by EPA to be even smaller (0.03-.0.04 deciviews).

While PacifiCorp's RP Reassessment application relies on new proposed NOX and SO2 reductions for improved visibility impacts, Wyoming reiterates again that it has analyzed NOX separately because SCR and SNCR are NOX -only control technologies. The Current Unit 1-2 NOX Controls (LNB/SOFA) have already reduced NOX from baseline by 8,063 tons/year. Based on information provided by PacifiCorp, installation of SCR alone would result in an additional NOX reduction from baseline of 5,848 tons/year. Alternatively, the installation of SNCR alone would result in an additional reduction from baseline of 1,655 tons/ year. 
In spite of the differences in tonnage reductions achievable by each, EPA's 2014 modeling demonstrates that installation of SCR on Units 1 & 2 would result in only modest incremental visibility benefits of .10 to .15 deciviews (per unit) when compared to LNB/SOFA on Units 1 and 2. Such modest improvements are not significant enough to outweigh the substantial cost of relying on the Current NOX Controls as the State's reasonable progress determination. The EPA has stated in other instances that it has "eliminated higher performing options -- SNCR + LNB, SCR, and SCR + LNB -- because their cost effectiveness values are significantly higher and/or the emission reductions are not that much higher than LNB..." See Fed. Reg. 58,570, 58,631; 77 Fed. Reg. 24,794 (0.27 dV improvement termed "small" and did not justify additional pollution controls in New York); 77 Fed. Reg. 11,879, 11,891 (0.043 to 0.16 ΔdV improvements considered "very small additional visibility improvements" that did not justify NOX controls in Mississippi); 77 Fed. Reg. 18,052, 18,066 (agreeing with Colorado's determination that "low visibility improvement (under 0.2 ΔdV)" did not justify SCR for Comanche units)); 77 Fed. Reg. 23,988, 24,012 (finding that that a 0.18 ΔdV improvement to be a "low visibility improvement" that "did not justify proposing additional controls" for SO2 on a Montana source). 
    Four Factor Analysis Weighing/Conclusion 
While SCR installation on Units 1 & 2 could be expected to be more efficient in controlling NOX emission than either SNCR installation or relying on the Current Unit 1-2 NOX Controls, the estimated capital costs, annual costs, and cost effectiveness are far higher for SCR and SNCR, compared with little modeled visibility benefit. SCR will produce solid waste every time the catalyst must be replaced, and will have higher electricity requirements. In contrast to SCR and SNCR, the Current NOX Controls are already being utilized, and do not require any additional time for compliance.
In light of the State of Wyoming's reconsideration of the analysis provided in the EPA's final Regional Haze Rule, along with the updated analysis provided by PacifiCorp, a proper re-weighing of the four reasonable progress factors (with significant emphasis being placed on the costs of compliance) demonstrates that the Current Unit 1-2 NOX Controls, including the current NOX emission limits of 0.26 lb/MMBtu (30-day rolling average), which apply to each unit, prevail as the reasonable choice for Jim Bridger Units 1 and 2. The State of Wyoming considers the amount that PacifiCorp has spent to date on NOX control technology at the Jim Bridger Plant and the attendant improvements in visibility to be sufficient for reasonable progress. Wyoming is therefore removing the requirement to install SCR at Jim Bridger's Units 1 and 2 as reasonable progress controls.  Wyoming's action is consistent with that of other EPA approvals.  See Arkansas, 83 Fed. Reg. 62,204, 62,232-33 (Arkansas considered various cost and visibility information, including total capital costs, $/dv, etc., and EPA approved Arkansas' Reasonable Progress analysis.).
    Supplemental Considerations and Additional Benefits of Voluntary Emission Limits
Although visibility is not a specific statutory factor for reasonable progress determinations, EPA has stated that States can consider visibility as part of a "reasonable progress determinations" See 81 FR 296, 310-334.Wyoming is exercising its inherent authority to consider PacifiCorp's proposed visibility enhancing reductions in haze causing pollutants can and should be used for additional strengthening and support in the State's revised reasonable progress determination set forth above. Section 5.0 of the 2007 RPG Guidance states that states "have flexibility in how to take into consideration [the] statutory factors and any other factors [the state has] determined to be relevant." The State of Wyoming considers PacifiCorp's proposed emission limits (which were designed and voluntarily proposed to reduce regional haze causing pollutants) to be relevant. Specifically, in its RP Reassessment application, PacifiCorp proposed to adopt a month-by-month plant-wide NOX and SO2 emission limits as described in Table 7.3.6-2.
Table 7.3.6-2. 	Voluntary Visibility Enhancing Emission Limits for the Jim Bridger Electric Generating Station

Month
Total Units 1-4
NOX Emission Limit
(monthly average basis)
Total Units 1-4
SO2 Emission Limit
(monthly average basis)
January
2,050 lb/hour
2,100 lb/hour
February
2,050 lb/hour
2,100 lb/hour
March
2,050 lb/hour
2,100 lb/hour
April
2,050 lb/hour
2,100 lb/hour
May
2,200 lb/hour
2,100 lb/hour
June
2,500 lb/hour
2,100 lb/hour
July
2,500 lb/hour
2,100 lb/hour
August
2,500 lb/hour
2,100 lb/hour
September
2,500 lb/hour
2,100 lb/hour
October
2,300 lb/hour
2,100 lb/hour
November
2,030 lb/hour
2,100 lb/hour
December
2,050 lb/hour
2,100 lb/hour

In addition to the proposed monthly limits, PacifiCorp also voluntarily proposed to restrict itself to an annual combined plant-wide NOX + SO2 emission cap of 17,500 tons/year (the combined set of proposed monthly and annual limits are referred to as the "Voluntary Visibility Enhancing Emissions Limits").
As a supplement to its RP Reassessment, PacifiCorp presented a visibility analysis of its proposed Voluntary Visibility Enhancing Emissions Limits. That analysis indicated that the Voluntary Visibility Enhancing Emissions Limits yielded greater modeled visibility improvement, lower costs, and fewer negative environmental impacts than installation of SCR or SNCR for Units 1 and 2. Specifically, the Current Unit 1-2 NOX Controls plus PacifiCorp's Voluntary Visibility Enhancing Emissions Limits produce better modeled visibility and greater environmental benefits than installation of SCR or SNCR. 
SCR and SNCR are control technologies that only reduce only one haze-causing pollutant, NOX, while the Voluntary Visibility Enhancing Emissions Limits reduce two haze-causing pollutants, NOX and SO2. EPA has recognized that SO2 is "the predominant cause of regional haze on the Colorado Plateau in the western US" (79 FR 5032, 5097), which means SO2 reductions generally result in better visibility improvement than NOX reductions. Based on PacifiCorp's application, installation of SCR on Units 1 and 2 would result in a NOX reduction from current operating potential of 5,848 tons/year, and installation of SNCR would result in a reduction of 1,655 tons/year from current operating potential. Comparatively, implementation of PacifiCorp's proposed Voluntary Visibility Enhancing Emissions Limits would result in a combined (NOX + SO2) reduction of 6,056 tons/year. Those limits will be enforceable through a Wyoming air permit, which will cap total operations on all four units. Naturally, a plant-wide limit caps all emissions from the source (including particulate matter), producing additional visibility benefits to the Current Unit 1-2 NOX Controls. 
PacifiCorp also provided incremental costs of compliance comparisons between SCR, SNCR and its Voluntary Visibility Enhancing Emissions Limits, which are provided in Table 7.3.6-3 below. 
The cost effectiveness estimates in Table 7.3.6-3 were calculated using total tons of reduced haze-causing pollutants, and assuming SO2 and NOX would have equivalent visibility impacts. This conservative approach provided the highest cost estimate for the Voluntary Visibility Enhancing Emissions Limits, and the lowest-cost estimates for SCR and SNCR. Furthermore, because the Jim Bridger Plant has already installed multiple NOX-emission controls (LNB & SOFA on Units 1-4 and SCR on Units 3-4), and the Voluntary Visibility Enhancing Emissions Limits include restriction on all 4 Units, the ton reductions reflected in the cost effectiveness estimates in Table 7.3.6-3 reflect reductions from current operating potential. Evaluating reductions from current operating potential provides a true-cost comparison of the cost and tonnage reduction of each technology. 
As shown in Table 7.3.6-3, NOX and SO2 reductions implementing the Voluntary Visibility Enhancing Emissions Limits are far more cost effective than the NOX only reduction using SCR or SNCR technologies. It should be noted that even if all three control technologies are compared on a NOX -only basis (excluding SO2), the Voluntary Visibility Enhancing Emissions Limits are still the lowest-cost option by significant margins.
Table 7.3.6-3. 	Incremental Costs of Voluntary Visibility Enhancing Emissions Limits Compared to SCR and SNCR for the Jim Bridger Electric Generating Station



                                Cost Estimates
                                    Unit ID
                              Control Technology
                      Incremental Control Efficiency (%)
                          Estimated Capital Cost ($)
                             Annual Cost ($/year)
                          Cost Effectiveness ($/ton)
                                     JB1,2
                                      SCR
                                      73
                                  280,856,000
                                  27,743,000
                                     4,744
                                     JB1,2
                                     SNCR
                                      20
                                  31,076,000
                                   9,046,000
                                     5,469
                                     JB1-4
                Voluntary Visibility Enhancing Emissions Limits
                                     10-20
                                   4,659,000
                                   2,115,000
                                      349

The RP Reassessment provided by PacifiCorp demonstrates that implementing the Voluntary Visibility Enhancing Emissions Limits across all 4 Units would also result in fewer overall energy and environmental impacts when compared to the installation of SCR or SNCR on Units 1 and 2 at the Jim Bridger Plant. PacifiCorp's application demonstrates that in addition to lower NOX emissions, the Voluntary Visibility Enhancing Emissions Limits would also result in less impacts from: Sulfur Dioxide (SO2); Mercury (Hg); Greenhouse Gases (GHG); Carbon Monoxide (CO); Carbon Dioxide (CO2); Particulate Matter (PM); Sulfuric Acid (H2SO4); Coal consumption; Coal Combustion Residual (CCR) production and disposal; and Raw Water consumption. 
As it relates to energy impacts, the Voluntary Visibility Enhancing Emissions Limits, as compared to the SCR installation, would reduce the Jim Bridger Plant's auxiliary load demand by approximately 10.4 MW, allowing the electrical energy which would have been required by the Units 1 and 2 SCRs to instead be directed to the power grid (which is enough energy to power approximately 8,761 average homes). The installation of SCR at Units 1 and 2 would result in the additional storage and use of ammonia (a hazardous substance), and would create more Coal Combustion Residuals (CCR) than implementation of Voluntary Visibility Enhancing Emissions Limits. Likewise, the installation of SNCR on Units 1 and 2 would require the storage and use of urea and would also create more CCR than the implementation of Voluntary Visibility Enhancing Emissions Limits. Additionally, the Voluntary Visibility Enhancing Emissions Limits of the RP Reassessment will result in the Jim Bridger Plant producing fewer greenhouse gases than would the installation of SCR or SNCR at Units 1 and 2.  
It should also be noted that under the requirement to install SCR on Units 1 and 2, the Jim Bridger Plant is not restricted on capacity factor  -  essentially annual heat input  -  and could operate with a potential average annual capacity factor of 100 percent. Implementing the Voluntary Visibility Enhancing Emissions Limits, prevent PacifiCorp from operating the Jim Bridger Plant in an unrestricted capacity and will permanently limit the operation capacity for all four Units.  Because adoption of the Voluntary Visibility Enhancing Emissions Limits will effectively limit annual boiler heat input, it will therefore also provide a reduction in the consumption of natural resources (water and coal). 
The proposed plant-wide Voluntary Visibility Enhancing Emissions Limits, as opposed to unit-specific limits, are useful to provide the entire facility the flexibility to "load follow" or accommodate intermittent influx of renewable energy into the western power grid, which has larger scale environmental impacts in Wyoming and across the West. 
To evaluate the visibility improvement associated with the Voluntary Visibility Enhancing Emissions Limits, and how it compared to the SCR installation, SNCR installation, and baseline emissions, PacifiCorp retained AECOM to perform updated CALPUFF visibility modeling (relying as closely as possible to previous CALPUFF modeling).  To provide for consistency and ease of comparison with previous analyses, the CALPUFF visibility model was chosen because it was the same model used to analyze the existing 2014 RP/LTS (SCR) requirements.  See 79 FR 5032.
The AECOM CALPUFF modeling report used three metrics to evaluate the CALPUFF modeling results: 
      1)	the 98th percentile modeled delta-dv, averaged over the 3 years modeled, applied to each Class I area individually;
      2)	the number of modeled days (summed over the 3 years modeled) with a plant impact above 0.5 delta-dv, applied to each Class I area individually; and
      3)	the number of modeled days (summed over the 3 years modeled) with a plant impact above 1.0 delta-dv, applied to each Class I area individually.
The updated CALPUFF modeling demonstrated that the Voluntary Visibility Enhancing Emissions Limits result in greater visibility improvement than SCR or SNCR under all three metrics.
Regarding the 98[th] percentile metric, the visibility impacts for the Jim Bridger Power Plant under the SCR, SNCR, and the Voluntary Visibility Enhancing Emissions Limits scenarios are 0.760, 0.930, and 0.653 deciviews, respectively. Thus, under any scenario using this metric, the Voluntary Visibility Enhancing Emissions Limits demonstrates the least impacts to visibility at Class I Areas.
Analyzing the CALPUFF-modeled number of days (over a three year period) that the Jim Bridger Power Plant would have a 0.5 dv impact on a given Class I Area, the Voluntary Visibility Enhancing Emissions Limits (based on the number of days of visibility impacts) results in a lesser (better) visibility impact than the other two control scenarios (SCR and SNCR).  Specifically, the modeled number of days over a three year period with visibility impacts above 0.5 dv for the SCR, SNCR, and the Voluntary Visibility Enhancing Emissions Limits of the RP Reassessment scenarios are 475, 597, and 371 days, respectively. Significantly, Voluntary Visibility Enhancing Emissions Limits result in 104 less days (almost 3.5 months over three years) of visibility impacts over 0.5 dvs than the SCR requirement. 
Finally, the modeled number of days (over a three year period) that the Jim Bridger Plant would  have a 1.0 dv impact on a given Class I area for the SCR, SNCR, and the Voluntary Visibility Enhancing Emissions Limits scenarios are 127, 195, and 108 days, respectively. Thus, under any scenario using this metric, the Voluntary Visibility Enhancing Emissions Limits demonstrates the least impacts to visibility at Class I Areas.   The Voluntary Visibility Enhancing Emissions Limits result in almost three less weeks (over a three year time period) of visibility impairment over 1.0 dv compared to the existing SCR requirements. Therefore, the Voluntary Visibility Enhancing Emissions Limits result in better modeled visibility improvements compared to either the SCR or SNCR scenarios for Units 1 or 2, as measured by the three metrics. 
While the Current Unit 1-2 NOX Controls alone provide adequate support for the State's revised reasonable progress determination, PacifiCorp has submitted separate permit applications which, if approved, will make the Voluntary Visibility Enhancing Emissions Limits enforceable and which provide further, additional support for Wyoming's decision to remove the requirement for PacifiCorp to install SCR on Jim Bridger Units 1 and 2.   
Considering NOX-only visibility impacts along with the four statutory reasonable progress factors, the Current Unit 1-2 NOx Controls are the reasonable choice for replacing SCR at Jim Bridger Units 1 and 2 as the State's reasonable progress determination. In addition, PacifiCorp's visibility enhancing proposal to limit overall operations at all four Jim Bridger Units adds support to Wyoming's reasonable progress revision, and ensures that visibility improvements greater than SCR installation will be achieved for the State of Wyoming. 
    Reasonable Progress Goals in the Federal Implementation Plan (FIP) 

The State of Wyoming has determined that no additional controls under the reasonable progress goal requirements, section 51,308(d)(1), are necessary to achieve reasonable progress for the first implementation period.  The Current Units 1-2 NOX Controls and the Wyoming New Source Review construction permit application for the Voluntary Visibility Enhancing Emissions Limits provide enforceable emission limits for the Jim Bridger Power Plant.  Based on key pollutants that contribute to visibility impairment in Wyoming's Class 1 Areas and reasonable weighing of the four factors along with consideration of the visibility benefits reasonable progress goals are met for the first implementation period of the Regional Haze Rule.


    Demonstrating noninterference under Section 110(l) of the Clean Air Act 

Section 110(l) of the Clean Air Act (CAA) indicates that EPA cannot approve a SIP revision if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress (RFP), or any other applicable requirement of the CAA. Therefore, the EPA will approve a SIP revision that removes or modifies control measure(s) in the SIP only after the State has demonstrated that such removal or modification will not interfere ("noninterference") with attainment of the National Ambient Air Quality Standards (NAAQS), Rate of Progress (ROP), RFP or any other applicable requirement of the CAA.  The approval of the Wyoming Regional Haze NOX and PM SIP revision meets the CAA 110(l) provisions concerning attainment and maintenance.  No areas in Wyoming are currently designated nonattainment for either of these two National Ambient Air Quality Standards (NAAQS) pollutants.  As all areas in Wyoming are attaining the NAAQS for these two pollutants with current emission levels, further reductions contained in the Current Unit 1-2 NOX Controls and the Voluntary Visibility Enhancing Emissions Limits will not interfere with attainment or maintenance.  The SIP revision will result in emission reductions beyond the status quo.
                                       
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                                    CHAPTER 8
                              LONG-TERM STRATEGY
                                       
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8.3 Additional Measures in Long-Term Strategy

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8.3.3 Long-Term Control Strategies for BART Facilities
In addition to the control strategies identified in Chapter 6 (Best Available Retrofit Technology (BART)) as BART determinations, the following requirements will be established through permit conditions or orders from the Environmental Quality Council for the individual BART facilities listed below:
Laramie River Station:
On March 8, 2010, Basin Electric Power Cooperative appealed the BART permit for the Laramie River Station before the Wyoming Environmental Quality Council (EQC).  The Department of Environmental Quality entered into a settlement agreement on November 16, 2010 with Basin Electric Power Cooperative to modify the BART permit.  On December 8, 2010, the Division held a State Implementation Plan (SIP) Hearing on Regional Haze. The SIP hearing was held in Cheyenne, Wyoming at the Laramie County Library, 2200 Pioneer Avenue.  At that time, the Division collected public comment on the Regional Haze SIP revisions.
After carefully considering all comments on revisions to the State Implementation Plan to address Regional Haze, the Division has determined that the following requirements for further NOx reduction taken from the Settlement Agreement Filed November 16, 2010 before the Wyoming EQC and incorporated into the EQC Order approving the Settlement, shall establish the NOx reduction requirements under the Long-Term Strategy of the Wyoming Regional Haze SIP for three units at Laramie River Station with respect to NOx and NOx only.
       1.         Total NOx emissions from Laramie River Station Units 1, 2 and 3 shall be further reduced to a plant-wide emission limit of 12,773 tons of NOx per year by December 31, 2017 and continuing thereafter, unless changed pursuant to new regulatory or permit requirements.
       2.         Basin Electric Power Cooperative shall submit to the Division a permit application for the 12,773 ton plant-wide NOx emission limit at the Laramie River Station by December 31, 2015.



Jim Bridger Power Plant:
With respect to the Jim Bridger Power Plant, PacifiCorp shall: (i) operate the installed SCRs on Units 3 and 4, with  NOx emissions rates for those two units not to exceed 0.07 lb/MMBtu on a 30-day rolling average; (ii) effective January 1, 2022 (as enforced by Permit #A0008217) implement lb/hour monthly-block emission limits as provided in Table 8.3.3-1; and (iii) effective January 1, 2022, implement a 12-month rolling emission cap of 17,500 tons/year of total NOx and SO2 emissions from the Jim Bridger Units 1-4 boilers.  
Table 8.3.3-1. 	Enforceable Monthly Block NOx and SO2 Emissions Limits Imposed on the Jim Bridger Electric Generating Station, Effective January 1, 2022.
Month
Total Units 1-4
NOX Emission Limit
(monthly average basis)
Total Units 1-4
SO2 Emission Limit
(monthly average basis)
January
2,050 lb/hour
2,100 lb/hour
February
2,050 lb/hour
2,100 lb/hour
March
2,050 lb/hour
2,100 lb/hour
April
2,050 lb/hour
2,100 lb/hour
May
2,200 lb/hour
2,100 lb/hour
June
2,500 lb/hour
2,100 lb/hour
July
2,500 lb/hour
2,100 lb/hour
August
2,500 lb/hour
2,100 lb/hour
September
2,500 lb/hour
2,100 lb/hour
October
2,300 lb/hour
2,100 lb/hour
November
2,030 lb/hour
2,100 lb/hour
December
2,050 lb/hour
2,100 lb/hour

The federally enforceable Monitoring, Recordkeeping, and Reporting requirements for the monthly-block NOx and SO2 limits listed in Table 8.3.3-1 are incorporated by reference from  Permit A0008217 into the SIP.   


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