63
                                    $2.05
                                   $0.0629
                                    $1.99
                                    $0.134
                                    $1.91
                          Post-Closure Plan revisions
                                   $0.0325
                                      63
                                    $2.05
                                   $0.0629
                                    $1.99
                                    $0.134
                                    $1.91
                            Property deed notation
                                   $0.00100
                                      63
                                   $0.0630
                                   $0.00188
                                   $0.0593
                                   $0.00385
                                   $0.0549
                         Subtotal: Documentation Costs

                                    $4.16
                                    $0.128
                                    $4.04
                                    $0.272
                                    $3.88
Avoided Documentation Costs
              Avoided documentation costs due to earlier closure
                                  ($0.00741)
                                      63
                                   ($0.467)
                                   ($0.0139)
                                   ($0.440)
                                   ($0.0267)
                                   ($0.382)
                                     TOTAL

                                    $3.70
                                    $0.114
                                    $3.60
                                    $0.245
                                    $3.49
Note: For a given present value, the associated annualized cost increases as the discount rate increases. This occurs because a greater annualized amount is needed to offset the greater discounting associated with a higher discount rate. For example, given a present value of $100, the annualized costs over 100 years are $7.01 under a seven percent discount rate, and $3.16 under a three percent discount rate. Where a stream of costs throughout a lengthy time horizon occurs, differing discount rates will lead to differing present values, because later years will be substantially more discounted with higher discount rates than lower ones; in these instances, the differential in present value can lead to an annualized cost that is lower under a lower discount rate than under a higher discount rate. However, the provisions of the proposed Part B rule consist of a series of costs and costs savings incurred towards the beginning of the 100-year period of analysis and then never again, leading to minimal differences in present values across discount rates, and creating a situation wherein annualized costs at seven percent tend to exceed annualized costs at three percent. If the costs and cost savings associated with these provisions were incurred or recurred in later years, it is likely that the annualized costs at seven percent would be less than the annualized costs at three percent.
3.4 	Costs Associated with Provision 4: Revised Notice of Intent to Close and Annual Closure Progress Reports
Provision 4 requires changes to paperwork requirements that apply to two different subsets of units depending on the paperwork already submitted for the units. The first requires all previously-submitted Notices of Intent to Close (NOIs) to be updated with an intended date of closure. The second is a new requirement for annual closure progress reports. EPA is proposing these changes to the paperwork requirements to increase transparency around the closure process and to provide a system of accountability for facilities' closure targets.
The costs associated with Provision 4 are described in Sections 3.4.1 and 3.4.2.
3.4.1 	Notice of Intent to Close Revisions
The first documentation cost is for facilities to re-post Notices of Intent to Close with an intended cease receipt of CCR date. At present, the notification requirements at 40 CFR 257 do not specify that an intended cease receipt of CCR date is a requirement of the NOI, and correspondingly, NOIs submitted to date generally do not discuss intended cease receipt of CCR date. This provision applies to all units that have already posted NOIs but have not yet closed. This universe contains 163 units. Exhibit 3-20 summarizes the universe derivation for the Provision 4 cost concerning re-posting Notices of Intent to Close.
          Exhibit 3-20
Provision 4: NOI Revisions Universe Derivation
Surface Impoundments
                                      533
Adjusted to remove 50 units already closed
                                      483
Adjusted to remove 320 units that have not already posted a Notice of Intent to Close
                                      163
Final Provision 3 Universe
                                   163 Units

The per-unit cost associated with this required documentation in 2020 is $51. This value is based on the NOI unit cost estimate from the 2015 CCR RIA and updated with 2018 labor rates. The total cost across the 163 units is $7,770, or $544 annualized across 100 years at seven percent.
There is no additional cost for this provision associated with future NOIs. The amendments to the NOI required under Provision 4 are minimal and will not require additional burden to complete; the only additional burden imposed by this cost is therefore the need to submit amended NOIs.
3.4.2 	Documentation Component 2: Annual Closure Progress Reports
The second documentation cost component is for facilities to post annual closure progress reports. At present, the notification and recordkeeping requirements at 40 CFR 257 do not require annual closure progress reports, and require only submissions associated with closure initiation and closure completion. This requirement affects the 407 units that have not yet certified completion of closure. Exhibit 3-21 summarizes the universe derivation for the closure plan revision requirement under Provision 4.
          Exhibit 3-21
Provision 4: NOI Revisions Universe Derivation
Surface Impoundments and Landfills
                                      768
Adjusted to remove 55 units already closed
                                      713
Adjusted to remove 306 units not planning to close
                                      407
                          Final Provision 4 Universe
                                   407 Units
Assuming a 10-year closure timeline, with the reporting requirements for this provision beginning in 2020, the per-unit total costs are $3,460. The per-report value is based on the annual inspection report item cost estimate from the 2015 CCR RIA with updated 2018 labor rates. The total cost across the 407 units is approximately $1.41 million, or $0.0992 million annualized across 100 years at seven percent. The incremental cost changes for Provision 4 are summarized in Exhibit 3-22.
Exhibit 3-22
Summary of Costs (Cost Savings) for Provision 4: Revised Notice of Intent to Close and Annual Closure Progress Reports
 (Millions of 2016$)
                                 Cost Element
                           Unit Costs (Cost Savings)
                                Units affected
                           Total cost (undiscounted)
                        Total Costs (Cost Savings) (3%)
                        Total Costs (Cost Savings) (7%)

                                  Annualized
                                 Present Value
                                  Annualized
                                 Present Value
Documentation Costs
Notice of Intent to Close revisions
                                  $0.0000510
                                     163
                                   $0.00831
                                  $0.000255
                                   $0.00807
                                  $0.000544
                                   $0.00777
Annual Closure Progress Reports
                                   $0.00346
                                     407
                                    $2.00
                                   $0.0541
                                    $1.71
                                   $0.0986
                                    $1.41
                                                                          TOTAL

                                    $2.01
                                   $0.0544
                                    $1.72
                                   $0.0992
                                    $1.42
Note: For a given present value, the associated annualized cost increases as the discount rate increases. This occurs because a greater annualized amount is needed to offset the greater discounting associated with a higher discount rate. For example, given a present value of $100, the annualized costs over 100 years are $7.01 under a seven percent discount rate, and $3.16 under a three percent discount rate. Where a stream of costs throughout a lengthy time horizon occurs, differing discount rates will lead to differing present values, because later years will be substantially more discounted with higher discount rates than lower ones; in these instances, the differential in present value can lead to an annualized cost that is lower under a lower discount rate than under a higher discount rate. However, the provisions of the proposed Part B rule consist of a series of costs and costs savings incurred towards the beginning of the 100-year period of analysis and then never again, leading to minimal differences in present values across discount rates, and creating a situation wherein annualized costs at seven percent tend to exceed annualized costs at three percent. If the costs and cost savings associated with these provisions were incurred or recurred in later years, it is likely that the annualized costs at seven percent would be less than the annualized costs at three percent.
3.5 	Interaction Effects Across Provisions
The proposed Part B rule includes four provisions that are analyzed separately in the sections above, effectively assuming that facilities undertake as many requirements and options under the various provisions as are relevant. This results in estimates of costs and cost savings as isolated potential changes to the baseline. However, certain provisions (particularly Provisions 1 and 2) represent different strategies and outcomes, and may affect other provisions (Provision 3 and Provision 4); Provision 2 changes the practices and costs associated with closure at participating facilities; facilities that successfully demonstrate alternative liners under Provision 1 may delay closure altogether for a number of years. A facility successfully demonstrating under Provision 1 is no longer subject to forced closure, and will not, therefore, change practices under Provision 2. Similarly, units changing from clean closure to waste-in-place closure strategies under Provision 2 will no longer be in the Provision 3 universe. In addition, changes in closure timing associated with Provision 1 change the timing of required annual closure reports under Provision 4, and may affect the incidence of changing documentation requirements under Provision 3. While in all cases the number and type of units that will ultimately change practices is uncertain, some intersection among the provisions is likely.
As a result, a final step in the estimation of costs in this RIA is to account for this intersection, based on an assumption that all four provisions become final. The analysis considers the likely changes to the respective universes of each provision as a result of facilities' expected behavior under the other provisions. A key assumption is that facilities' first preference will be for existing units to remain open as a result of successfully demonstrating under Provision 1. The Provision 1, Scenario 1 analysis estimates that roughly 10 existing units will be exempt from forced closure following successful demonstrations. These are excluded from the universes of units undergoing closure in Provisions 2. Provisions 3 and 4 comprise documentation costs that are minor in magnitude relative to Provisions 1 and 2; the effects of Provision 1 on delays in their paperwork are minimal and not separately assessed.
For simplicity, the cost calculations for assessing the interaction effects among the provisions apply the appropriate unit counts to the average per-unit cost of the relevant aspects of the provision, effectively assuming that every unit that is affected is "average." These adjustments are presented as net changes (costs or cost savings) to the relevant provisions. We separate calculations for each co-proposed option in Provision 2, as well as each of the two scenarios for each co-proposed option. These results are summarized in Exhibit 3-23.

Exhibit 3-23
Summary of Costs (Cost Savings): Interaction Effects Across Provisions
 (Millions of 2016$)
                                 Cost Element
                           Unit Costs (Cost Savings)
                                Units affected
                           Total cost (undiscounted)
                        Total Costs (Cost Savings) (3%)
                        Total Costs (Cost Savings) (7%)

                                  Annualized
                                      PV
                                  Annualized
                                      PV
Provision 2
Units Removed from Co-Proposed Option 1, Scenario 1 and 2 Due to Accepted Demonstrations under Provision 1
                                    $5.05
                                      10
                                    $54.0
                                    $1.61
                                    $50.9
                                    $3.31
                                    $47.2
Units Removed from Co-Proposed Option 2, Scenario 1 Due to Accepted Demonstrations under Provision 1
                                    $7.42
                                      10
                                    $79.4
                                    $2.37
                                    $74.8
                                    $4.86
                                    $69.4
Units Removed from Co-Proposed Option 2, Scenario 2 Due to Accepted Demonstrations under Provision 1
                                    $15.3
                                      10
                                     $163
                                    $4.87
                                    $153.9
                                    $10.0
                                     $143
Provision 3
Units Removed from Provision 3 Due to Accepted Demonstrations under Provision 1
                                   ($0.0587)
                                      10
                                   ($0.628)
                                   ($0.0193)
                                   ($0.609)
                                   ($0.0411)
                                   ($0.587)
Units Removed from Provision 3 Due to Switching to Waste in Place Under Co-Proposed Option 1, Scenario 1
                                   ($0.0587)
                                      2
                                   ($0.117)
                                   ($0.0036)
                                   ($0.114)
                                   ($0.0077)
                                   ($0.110)
Units Removed from Provision 3 Due to Switching to Waste in Place Under Co-Proposed Option 1, Scenario 2
                                   ($0.0587)
                                      17
                                   ($0.997)
                                   ($0.0306)
                                   ($0.968)
                                   ($0.0653)
                                   ($0.932)
Units Removed from Provision 3 Due to Switching to Waste in Place Under Co-Proposed Option 2
                                   ($0.0587)
                                      27
                                   ($1.584)
                                   ($0.0487)
                                   ($1.538)
                                   ($0.1037)
                                   ($1.480)
Provision 4
Units Removed from Provision 4, Annual Closure Progress Reports Due to Accepted Demonstrations Under Provision 1
                                  ($0.00346)
                                      10
                                   ($0.0370)
                                  ($0.00114)
                                   ($0.0359)
                                  ($0.00242)
                                   ($0.0346)
Totals
TOTAL CHANGES UNDER CO-PROPOSED OPTION 1, SCENARIO 1
                                    $53.2
                                   $1.5875
                                    $50.2
                                    $3.26
                                    $46.5
TOTAL CHANGES UNDER CO-PROPOSED OPTION 1, SCENARIO 2
                                    $52.4
                                   $1.5605
                                    $49.3
                                    $3.20
                                    $45.6
TOTAL CHANGES UNDER CO-PROPOSED OPTION 1, SCENARIO 1
                                    $77.2
                                    $2.30
                                    $72.7
                                    $4.71
                                    $67.3
TOTAL CHANGES UNDER CO-PROPOSED OPTION 1, SCENARIO 1
                                     $161
                                    $4.80
                                     $152
                                    $9.85
                                     $141

3.6	Summary of Expected Costs and Cost Savings
The cost and cost savings calculations discussed in Sections 3.1-3.4 are summarized in Exhibit 3-24.
                 Exhibit 3-24
Summary of Costs (Cost Savings)
                   Proposed Part B Rule
 (Millions of 2016$)
                                 Cost Element
                        Total Costs (Cost Savings) (3%)
                        Total Costs (Cost Savings) (7%)

                                  Annualized
                                 Present Value
                                  Annualized
                                 Present Value
Provision 1
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2

                                    ($4.98)
                                    ($2.49)
                                    ($157)
                                    ($78.6)
                                    ($8.63)
                                    ($4.32)
                                    ($123)
                                    ($61.6)
Provision 2, Co-Proposed Option 1
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2

                                    ($22.8)
                                    ($37.2)
                                    ($722)
                                   ($1,170)
                                    ($40.7)
                                    ($65.3)
                                    ($581)
                                    ($932)
Provision 2, Co-Proposed Option 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2

                                    ($47.7)
                                    ($86.0)
                                   ($1,510)
                                   ($2,720)
                                    ($85.2)
                                    ($140)
                                   ($1,220)
                                   ($1,990)
Provision 3 (cost increase)
                                    $0.114
                                    $3.60
                                    $0.245
                                    $3.49
 Provision 4 (cost increase)
                                   $0.0544
                                    $1.72
                                   $0.0992
                                    $1.42
Interaction Effects, Provision 2, Co-Proposed Option 1
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2

                                    $1.59
                                    $1.56
                                    $50.2
                                    $49.3
                                    $3.26
                                    $3.20
                                    $46.5
                                    $45.6
Interaction Effects, Provision 2, Co-Proposed Option 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2
                                  Scenario 1
                                  Scenario 2

                                    $2.30
                                    $4.80
                                    $72.7
                                     $152
                                    $4.71
                                    $9.85
                                    $67.3
                                     $141

                                    Low End
                                   High End
                                    Low End
                                   High End
                                    Low End
                                   High End
                                    Low End
                                   High End
                              TOTAL COST SAVINGS
                                    ($23.3)
                                    ($86.0)
                                    ($745)
                                   ($2,719)
                                    ($41.5)
                                    ($138)
                                    ($591)
                                   ($1,967)
Scenario Assumptions
Provision 1
- Scenario 1: Assumes 20 units apply to submit demonstration, 20 units approved to submit the demonstration, and 10 see accepted demonstrations.
- Scenario 2: Assumes 10 units apply to submit demonstrations, 10 units are approved to submit the demonstration, and 5 see accepted demonstrations.
Provision 2, Co-Proposed Option 1
- Scenario 1: Assumes EPA rejects a share of modified closure plans detailing CCR to be used in closure, at a rate of 50 percent of units currently exceeding the Groundwater Protection Standards and 50% of units failing the aquifer location restriction.
- Scenario 2: Assumes EPA accepts all modified closure plans.
Provision 2, Co-Proposed Option 2
- Scenario 1: Assumes the quantities of beneficially used CCR in closure align with the same existing estimates of fill required in closure used in Co-Proposed Option 1.
- Scenario 2: Assumes that 50 percent of units will beneficially use CCR in closure at quantities exceeding existing estimates of fill required in closure at a rate equaling that of the Yates facility in Georgia, which has closure plans on file detailing a 40 foot thick layer of CCR to be used in closure.
Note: For a given present value, the associated annualized cost increases as the discount rate increases. This occurs because a greater annualized amount is needed to offset the greater discounting associated with a higher discount rate. For example, given a present value of $100, the annualized costs over 100 years are $7.01 under a seven percent discount rate, and $3.16 under a three percent discount rate. Where a stream of costs throughout a lengthy time horizon occurs, differing discount rates will lead to differing present values, because later years will be substantially more discounted with higher discount rates than lower ones; in these instances, the differential in present value can lead to an annualized cost that is lower under a lower discount rate than under a higher discount rate. However, the provisions of the proposed Part B rule consist of a series of costs and costs savings incurred towards the beginning of the 100-year period of analysis and then never again, leading to minimal differences in present values across discount rates, and creating a situation wherein annualized costs at seven percent tend to exceed annualized costs at three percent. If the costs and cost savings associated with these provisions were incurred or recurred in later years, it is likely that the annualized costs at seven percent would be less than the annualized costs at three percent.

Incremental Benefits of the Proposed Part B Rule

This chapter discusses the incremental benefits associated with the proposed Part B rule. These include impacts on the human health and environmental benefits estimated as resulting from the 2015 CCR Rule. This chapter qualitatively identifies and describes the following benefits impacts associated with the proposed Part B rule as follows:
 Section 4.1 -- Reduced benefits associated with beneficial use markets under Provision 2, Co-Proposed Option 2, resulting from the potential diversion of CCR away from structured beneficial use markets and high-value uses with significant environmental benefits to lower-value fill applications.
 Section 4.2 -- Human health and environmental impacts (reduced benefits due to increased exposures) associated with increased potential for groundwater contamination resulting from increased placement of CCR in both open and closing units under Provisions 1 and 2. As well as potential benefits associated with unit consolidation.
4.1	Beneficial Use Market Impacts
The RIA for the 2015 CCR Rule applied a linear programming modeling effort to assess the impacts of that rule related to increased beneficial use of CCR in a range of applications. Specifically, that effort estimated the extent to which the increase in CCR disposal costs associated with that rule would create an additional economic incentive for coal-fired electric utility plants to divert CCR to beneficial use rather than disposal. This beneficial use market analysis culminated in two monetized benefits: avoided disposal costs, addressed in this RIA in Chapter 3; and environmental and human health benefits associated with a reduced use of virgin materials in various applications, due to projected increases in the use of CCR beneficial use applications including gypsum wallboard and concrete. These benefits are estimated at an annualized value of $21.9 million in the 2015 CCR RIA (under a seven percent discount rate, in 2013 dollars).
The baseline for the proposed Part B rule includes the effects of the 2015 CCR Rule, and therefore the additional beneficial use prompted by that rule, inclusive of its environmental and human health benefits. By allowing more cost-effective placement of CCR in existing management units than allowed in the baseline, however, Provision 2 of the proposed Part B rule, potentially reduces or removes the economic advantage of selling CCR into the established beneficial use market for off-site applications, and affects the estimated environmental and human health benefits of those applications.
Both Co-Proposed Option 1 and Option 2 of Provision 2 of the proposed Part B rule reduce the costs incurred by CCR-generating facilities. Currently, facilities with CCR management units subject to forced closure cannot continue to place CCR in a unit after the cease receipt of CCR deadline, and must choose among the following options for managing ongoing CCR generation: sending the material off-site for disposal, selling the CCR into the beneficial use market for use in offsite applications, or (where available) disposing of the CCR in a different on-site CCR management unit that is still operating.
Under the proposed Part B rule, these facilities also have the option of placing CCR into their subject-to-forced-closure unit(s). To the extent that facilities respond to this alternative array of options by placing additional CCR into unit(s) subject to forced closure in lieu of making it available for beneficial use, the overall quantity of CCR beneficially used in offsite applications may decline. Under Provision 2, Co-Proposed Option 1, the CCR used to support closure of the CCR unit (e.g., for use in fill and capping operations) is not considered beneficial use at all, and the total beneficial use of CCR would be affected. Under Provision 2, Co-Proposed Option 2, the designation of beneficial use still applies to the CCR, but it is assigned to a low-value use as fill and diverted from markets that may include high-value applications in concrete and other materials. If this occurs, the environmental and human health benefits associated with beneficial use of CCR will correspondingly decrease.
As described in the RIA for the 2015 CCR Rule, beneficial use of CCR is driven in large part by geographic and regional differences in CCR demand. At the facility level, additional decision-making drivers include the array of management units (either on-site and/or off-site) available for CCR placement, the costs (amortized construction, operation, and end-of-life costs, or tipping fees) associated with such placement, and transportation costs associated with moving the CCR from the generating facility to the beneficial use location. The quality of the CCR itself may also play a role in its suitability for beneficial use. The extent of impacts on beneficial use, and therefore on the environmental and human health benefits of this beneficial use, of Provision 2 depend entirely on these factors, and therefore cannot be directly estimated without a characterization of the markets and cost structures faced by each CCR-generating facility.
For example, a hypothetical facility may be proximately located to multiple CCR beneficial users who express high demand for CCR as an input into their products (e.g., concrete). Regardless of the lower overall disposal cost faced by this facility under Provision 2, continuing to make CCR available for beneficial use may be the most cost-effective use of this facility's CCR. Therefore, for this hypothetical facility, Provision 2 may not result in decreased beneficial use, and therefore no impacts on human health and environmental benefits associated with beneficial use.
However, a different hypothetical facility may be located in a low-demand area, or may have closure costs that are high due to the size and structure of the unit. Given the CCR placement prohibition associated with the cease receipt of CCR deadline in the baseline, as well as the full array of pollution controls required for CCR management units, this facility may still choose, under the baseline, to make its CCR available for beneficial use, to the extent that doing so results in a lower per-ton CCR management cost than disposing of the CCR in either its existing (non-subject to forced closure) units, or off site. Under Provision 2, the facility will be able to compare the per-ton cost of disposing the CCR in its unit(s) subject to forced closure to selling the CCR for off-site beneficial use. If the former is lower than the latter, the facility may choose to re-orient its CCR into its unit(s) subject to forced closure rather than continue to make it available for off-site beneficial use. In this instance, off-site beneficial use, including potentially some high-value uses with considerable environmental benefits, will decrease, as will the corresponding human health and environmental benefits.
The RIA for the 2015 CCR Rule estimated annualized human health and environmental benefits associated with avoided air pollution and resource use from a projected increased in beneficial use due to the changes in the cost of disposal under the rule. The annualized value of these benefits is approximately $21.9 million under a seven percent discount rate (2013$). Note that this figure is not adjusted to account for universe updates that have taken place since the 2015 CCR Rule went into effect, including closure of a number of facilities and implementation of state regulations requiring clean closure. As a result, the 2015 analysis may underestimate current benefits associated with this aspect of the 2015 CCR Rule, due to increased availability of ash from clean closing units, or may overestimate these benefits due to an overall reduction in CCR generation since 2015.
According to information provided by American Coal Ash Association, CCR is currently being used in impoundment closure activities. ACAA production and use survey data indicate that 434,675 short tons of CCR were used in "CCR pond closure activities" in 2016, increasing to 4,469,130 short tons (approximately six percent of all CCR beneficial use) in 2017, and decreasing to 3,227,295 short tons (approximately five percent of all CCR beneficial use) in 2018. The 2015 CCR RIA estimated a per-ton environmental and human health benefit of the beneficial use of CCR associated with the avoided use of virgin materials, e.g., the benefit of using one ton CCR in lieu of virgin materials in the production of portland cement was estimated at $69.90 (2011 dollars). That RIA similarly estimated the environmental and human health benefit of using one ton of CCR in lieu of virgin fill materials as $2.28. Therefore, every ton of CCR diverted from higher-value productive uses as a result of Provision 2 results in a corresponding reduction in the benefits of the beneficial use of CCR. While Provision 2, Co-Proposed Option 2 may nominally result in increased quantities of CCR dedicated to "beneficial use" overall, the placement of CCR in units subject to forced closure as "fill" is a lower-value use. As a result, the environmental benefits anticipated in the 2015 estimate will most likely decrease. Moreover it is not self-evident that use of CCR as fill will replace the use of virgin materials ton-for-ton or whether other, less materials-intensive closure options may be more economical, such as clean closure and re-purposing of the excavated ash towards higher-value beneficial uses.
Elimination of the annualized estimate of roughly $20 million in beneficial-use-related benefits (under a seven percent discount rate, 2013$) reflects one potential estimate of the potential impacts associated with Provision 2. If Provision 2 results in a reallocation of sufficient material away from high-end, off-site uses, it could eliminate some or all beneficial use-related benefits driven by the 2015 CCR Rule. To the extent that Provision 2 results in only a partial decrease in off-site beneficial use relative to the increases estimated in the 2015 CCR Rule, and affects only the lower-value uses (fill), the effects on the beneficial-use-related benefits of the 2015 CCR rule may be modest.
Provision 2, Co-Proposed Option 2 places fewer restrictions on the placement of CCR in units subject to forced closure than Co-Proposed Option 1 (see Section 3.2). Therefore, potential reductions in human health and environmental benefits due to decreases in beneficial use will potentially be greater under Co-Proposed Option 2 than Co-Proposed Option 1.

4.2	Human Health and Environmental Impacts associated with Groundwater Contamination
The 2015 CCR RIA identified an array of human health and environmental impacts, including avoided groundwater contamination by CCR surface impoundments, reduced incidence of cancer, avoided IQ losses and reduced need for specialized education, non-market water quality benefits, protection of threatened and endangered species, and reduced groundwater withdrawals. The annualized values of these benefits from the 2015 CCR rule were estimated as $21.9 million (seven percent discount rate, 2013 dollars). Such impacts generally revolved around reductions in groundwater and surface-water contamination associated with the 2015 CCR Rule, through reductions in the universe of unlined surface impoundments, as well as increased monitoring, detection, and corrective action/groundwater remediation requirements.
The 2018 court decisions baseline imposes a uniform closure date on all unlined, including clay lined, surface impoundments and therefore could further reduce human health and environmental impacts associated with groundwater contamination. However, under the proposed Part B rule, certain provisions may affect these types of benefits and result in an overall decrease in benefits to human health and the environment, while others may increase said benefists.
Specifically, under Provision 1, and as noted in Chapter 3, a subset of units that submit successful applications but whose alternate liner demonstrations are ultimately rejected by EPA will effectively receive a modest closure deadline extension associated with the proposed alternate liner demonstration procedures. This would occur as a result of the proposed two-step process that includes an initial eligibility application followed by the submission of the actual liner demonstration. The effect of such a time extension (i.e., during the period when the liner demonstration is being evaluated by EPA or a Participating State Director) on groundwater contamination is unknown, but expected to be minimal because EPA (or a Participating State Director) will issue its decision on the liner demonstration submittal within four months of receiving a complete demonstration from the applicant.
For those CCR units that take advantage of Provision 2 (both under Co-Proposed Option 1 and Co-Proposed Option 2), the Agency estimates that these units (surface impoundments) will likely receive greater volumes of CCR for disposal as compared to the baseline. However, these volume increases would occur after the CCR unit has been dewatered and during closure of the unit. Moreover, these volume increases are expected to be mostly off-set by disposal volume decreases in other CCR units included in the baseline. EPA expects the CCR that would be used in the closure of units (e.g., used to achieve the subgrade elevations necessary to support the final cover system) would be sourced from other CCR units that will be closed by removal of CCR. To put another way, EPA expects most of the CCR used during closure to originate from unit consolidation of multiple units into a smaller number of units.
EPA believes there can be benefits associated with closing units under the conditions prescribed in this proposal, especially when unit consolidation is the source of CCR used to close a unit as EPA anticipates. For example, consolidating multiple units into a single unit would result in an overall smaller CCR unit footprint. Closing two 10-acre impoundments by removal of CCR and using the removed CCR for the purpose of achieving subgrade elevations necessary to support the closure and final cover system of a third 35-acre CCR unit is an example of consolidation resulting in a smaller CCR disposal footprint. One environmental benefit of this closure scenario would be the elimination of any long-term threat of impact to groundwater and surface water from 20 acres of land (two 10-acre units) as well as concerns about the long-term performance of a final cover system had these units been closed alternatively with CCR in place. In addition, upon closure of the two 10-acre impoundments, a total of 20 acres of land would become available for other uses. Finally, there may be benefits to allowing an owner or operator to focus their long-term monitoring, care and cleanup obligations on a single unit rather than multiple units.
Units closing with CCR under Provision 2, Co-Proposed Option 1 will need to demonstrate in the closure plan submitted to EPA (or Participating State Director) for approval that the unit will be closed in accordance with the closure performance standards under § 257.102(d) and that the placed CCR will remain contained (i.e., isolated) in the unit after closure. Doing so would limit CCR in the unit coming into contact with water and preventing releases to the environment, including releases through surface transport by precipitation runoff, releases to soil and groundwater, wind-blown dust, and catastrophic unit failures. EPA believes that units closed consistent with these proposed requirements, which also include volumetric and temporal limits on CCR placement, under a closure plan approved by the Administrator or Participating State Director would meet the RCRA section 4004(a) protectiveness standard. Units closing under Co-Proposed Option 2 would also need to be closed in accordance with the closure performance standards and would need to be closed consistent with the conditions specified in the definition of "beneficial use of CCR." The fourth criterion of this definition requires that when unencapsulated use of CCR involves placement on the land of 12,400 tons or more in non-roadway applications, the user must demonstrate that environmental releases to groundwater, surface water, soil, and air are comparable to or lower than those from analogous products made without CCR, or that environmental releases to groundwater, surface water, soil, and air will be at or below relevant regulatory and health-based benchmarks for human and ecological receptors during use. EPA's analyses indicate the mass of CCR that would be used during closure of a CCR unit under this option would exceed the 12,400-ton threshold, thus triggering the need for the owner or operator to conduct the environmental demonstration. Additional information can be found in the preamble to the 2015 CCR Rule (see 80 FR 21347-54).

Other Required Analyses

As required by applicable statutes and executive orders, this chapter presents other supplemental analyses for the proposed Part B rule, including:
 Electricity Price and Energy Market Impacts (Executive Order 13211)
 Small Business Impact Analysis  -  Regulatory Fairness Act/Small Business Regulatory Enforcement Fairness Act (RFA/SBREFA)
 Potential Impacts to Minority and Low-Income Populations (Executive Order 12898)
 Potential Impacts to Children (Executive Order 13045)
 Unfunded Mandate Reform Act (UMRA), Federalism Implications (Executive Order 13132), and Consultation and Coordination with Indian Tribal Governments (Executive Order 13175)
 Effects on Employment
 Reducing Regulation and Controlling Regulatory Costs (Executive Order 13771)
5.1	Electricity Price and Energy Market Impacts (Executive Order 13211)
The 2001 Executive Order 13211, "Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use," requires federal agencies to evaluate and prepare a statement on any potential adverse effects of economically-significant rulemakings on energy supply, distribution or use, including shortfall in energy supply, energy price increases, and increased use of foreign energy supplies. The Office of Management and Budget provides guidance for implementing this Executive Order, outlining nine numerical indicators (or thresholds) that may constitute "a significant adverse effect" when compared with the regulatory action under consideration.
For the 2015 CCR Rule, EPA analyzed the potential impact on electricity prices relative to the "in excess of one percent" threshold. Using the Integrated Planning Model (IPM), EPA concluded that the 2015 CCR Rule could potentially increase the weighted average nationwide wholesale price of electricity between 0.18 percent and 0.19 percent in the years 2020 and 2030, respectively. However, in the four years since 2015, wholesale and retail electricity prices in the U.S. have remained constant or declined in real terms, suggesting that continued changes in the price and availability of renewable energy and natural gas have offset any potential impact of the rule on wholesale and consumer prices. As the proposed Part B rule represents a cost savings rule relative to the 2015 CCR Rule, any potential impact on wholesale electricity prices would be to reduce the impact originally estimate for the 2015 CCR Rule. As a result, this proposed Part B rule is not expected to meet the criteria of a "significant adverse effect" on the electricity markets as defined by Executive Order 13211.
5.2	Small Business Impact Analysis (RFA/SBREFA)
According to the requirements of the 1980 Regulatory Flexibility Act (RFA) as amended by the 1996 Small Business Regulatory Enforcement Fairness Act (SBREFA), when a Federal agency publishes a notice of rulemaking for any proposed or final rule, it must make available for public comments a regulatory flexibility analysis that describes the effect of the rule on small entities (i.e., small businesses, small organizations, and small government jurisdictions). No regulatory flexibility analysis is required; however, if the head of an agency certifies that the rule will not have a significant economic impact on a substantial number of small entities (SISNOSE). SBREFA amended the RFA to require Federal agencies to provide a statement of the factual basis for certifying that a rule will not have significant economic impact on a substantial number of small entities.
Consistent with EPA's 2006 RFA/SBREFA guidance, the 2015 RIA analyzed impacts to small businesses by comparing the estimates of annualized regulatory compliance costs for each entity size category with estimates of annual revenues for each type of entity against the following three impact thresholds:
 Less than one percent of annual revenues;
 Between one percent and three percent of annual revenues; and
 More than three percent of annual revenues.
Based on these thresholds, the 2015 RIA concluded that the 2015 CCR Rule would not have a SISNOSE, specifically:
 For none of the categories of small entities do costs exceed three percent of revenues
 For three of the four categories (cities, companies, cooperatives), costs do not exceed one percent of revenues
 Of the 242 affected entities, 81 would be considered small entities for RFA purposes. Of the 81 small entities affected, only six entities (7.4 percent of affected small entities) were expected to experience costs exceeding one percent of revenues, and only one entity was expected to experience costs exceeding three percent of revenues.
As the proposed Part B rule represents a reduction in the estimated costs of compliance as compared to the 2015 CCR Rule, for which EPA previously determined the 2015 rule would not have a SISNOSE, this RIA concludes that the proposed Part B rule will not have a SISNOSE.
5.3	Potential Impacts to Minority and Low-Income Populations (Executive Order 12898)
Executive Order 12898 (Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations) (59 FR 7629, Feb. 16, 1994) directs federal agencies, to the greatest extent practicable and permitted by law, to identify and address, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.
The RIA for the 2015 CCR Rule evaluated the demographic characteristics of potentially affected communities and concluded that the rule would not result in new disproportionate risks to minority or low-income populations because the 2015 CCR Rule is risk-reducing.
In the absence of an updated risk assessment identifying the impact of the larger number of unlined and leaking units than were originally modeled (including the role and timing of corrective action), the impact of the Part B rule on risks to human health and the environment is unclear relative to the updated baseline. Moreover, because the 2015 CCR Rule demographic screening assessment determined that coal-fired power plants tend to be located in areas characterized by low-income populations, the likely increased disposal of CCR on site at coal-fired power plants under this rule may have a disproportionate impact on those populations.
5.4	Potential Impacts to Children (Executive Order 13045)
The 2015 CCR Rule examined the potential impact of the 2015 CCR Rule on children's risk. This evaluation concluded that distribution of risk across the children's demographic is not likely to change significantly as a result of the 2015 CCR Rule. Furthermore, the analysis found that the percent of all plants with impoundments that exceed the national proportion of children is 38.5 percent (104 of 270 plants for which population data are available), suggesting that reductions in risk at these plants would benefit children.
In the absence of an updated risk assessment identifying the impact of the larger number of unlined and leaking units than were originally modeled (including the role and timing of corrective action), the impact of the Part B rule on risks to human health and the environment is unclear relative to the baseline established by the 2015 CCR Rule.
5.5	Unfunded Mandate Reform Act (UMRA) and Federalism Implications Analysis (Executive Order 13132)
These analyses evaluate the proposed Part B rule impacts relative to requirements under the Unfunded Mandates Reform Act and Executive Order 13132, Federalism Implications Analysis.
5.5.1	Unfunded Mandate Reform Act (UMRA)
Among its other purposes and federal agency rulemaking requirements, the Unfunded Mandates Reform Act (UMRA) requires federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on state, local, and tribal governments and on the private sector, to determine whether any proposed rulemaking may result in "any Federal mandate that may result in the expenditure by state, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one year." As the proposed Part B rule is a cost savings rule, this analysis does not expect the rule to result in expenditures, in aggregate greater than $100 million in any one year; rather this analysis expects that expenditures of any state, local and tribal governments affected by the rule to decrease.
5.5.2.	Federalism (Executive Order 13132)
The 1999 Federalism Executive Order 13132 furthers the policies of UMRA by establishing federalism principles, federalism policymaking criteria, and a state and local government consultation process for the development of federal regulations with implications for federalism. The proposed Part B rule is not expected to have substantial direct effects on states, on the relationship between the federal government and the states, or on the distribution of power and responsibilities among the various levels of government because it is a cost savings rule. A portion of the cost savings associated with the proposed Part B rule will accrue to state and local governments that own or operate electric utilities.:
5.5.3.	Consultation and Coordination with Indian Tribal Governments (Executive Order 13175)
The 2000 Executive Order 13175 directs federal agencies to coordinate and consult with Indian tribal governments whose interests might be directly and substantially affected by activities on federally administered lands. This action has tribal implications because it would impose requirements on facilities located in Indian country. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law.
EPA has identified that three of the 414 coal-fired electric utility plants (in operation as of 2012) are located on tribal lands. The three facilities are: (1) the Navajo Generating Station in Coconino County, Arizona, which is operated by the Arizona Salt River Project and owned by the Navajo Nation; (2) the Bonanza Power Plant in Uintah County, Utah, which is operated by the Deseret Generation and Transmission Cooperative and owned by the Ute Indian Tribe; and (3) the Four Corners Power Plant in San Juan County, New Mexico, which is operated by the Arizona Public Service Company and owned by the Navajo Nation. The Navajo Generating Station and the Four Corners Power Plant are on tribal trust lands belonging to the Navajo Nation, while the Bonanza Power Plant is located on tribal trust lands within the Uintah and Ouray Reservation of the Ute Indian Tribe. Because CCR units are land-based units, the fact that these CCR facilities are located on tribal trust land means that the facility owners within the meaning of the CCR Rule are the tribal trust beneficial landowner tribes. The Agency continues to believe that the facility operators will bear all direct compliance costs associated with the above-mentioned rules and proposed rules.  However, to the extent that an operator fails to comply with a federal CCR requirement, CCR facility owners may also be held liable.
Relative to the baseline, this RIA anticipates expenditures to remain the same or decrease at the three plants located on tribal lands. Specifically, this RIA expects cost savings to accrue to the Four Corners Power Plant in San Juan County, New Mexico. This plant has one surface impoundment and therefore may incur cost savings under Provision 2, modification of the date by which unlined surface impoundments must cease receiving CCR and initiate closure.
Accordingly, this RIA concludes that proposed Part B rule is not anticipated to have tribal implications as specified in Executive Order 13175.
5.6	Effects on Employment
The 2015 CCR RIA examined the potential effects on employment in the following seven sectors or sub-sectors, including coal fired electric utilities, pollution control supplier industries, virgin material suppliers, coal mining, natural gas extraction, natural gas utility plants, and sectors affiliated with constructing new gas power plants.
The analysis concluded that the 2015 CCR Rule would have at most modest impacts on employment, and would potentially drive increases in employment at utilities from the Operations and Maintenance costs related to compliance and at pollution control supplier industries from the capital costs related to the construction of impoundment liners and the conversion from wet to dry handling of CCR.
This rule may reduce some compliance-related effort but only by a marginal amount. The impact of CCR unit closures on jobs associated with beneficial use or wet-dry conversion are unknown, as these are market-driven, corporate-level decisions based on long-term capital planning and commodities markets, and schedules for unit closure represent only one of several factors that enter into these decisions. The impact that Provision 2 will have on the sale of CCR into existing beneficial use markets could affect employment in that sector relative to the 2015 CCR Rule baseline. Diversion of CCR to on-site uses may reduce projected growth in the CCR beneficial use market.

 Appendix A Baseline CCR Management Costs Considered and Not Considered in this RIA

                                   Exhibit A
    Baseline CCR Management Costs Considered and Not Considered in this RIA
                                 Cost Category
                Pre-2015 Baseline Calculated for 2015 CCR Rule
Incremental Cost in 2015 CCR Rule (millions of $, annualized at 7% over 100-year time horizon, 2013$)
                       Affected by Proposed Part A Rule?
                       Affected by Proposed Part B Rule?
                  Effort Needed to Update Baseline Estimates
Groundwater monitoring
                                      Yes
                                     $2.80
                                      No
                                      No
                  Moderate  -  requires research and modeling
Bottom liners
                                      Yes
                                     $297
                                      Yes
                                      Yes
                        Moderate  -  requires modeling
Leachate collection systems
                                      Yes
                                     $18.4
                                      Yes
                                      Yes
                        Moderate  -  requires modeling
Dust controls
                                      Yes
                                     $3.36
                                      No
                                      No
                  Moderate  -  requires research and modeling
Run-on/run-off controls
                                      Yes
                                     $13.0
                                      No
                                      No
                  Moderate  -  requires research and modeling
Location restrictions
                                      Yes
                                     $20.0
                                      No
                                      No
               High  -  requires extensive research and modeling
Closure capping
                                      Yes
                                     $12.0
                                      Yes
                                      Yes
               High  -  requires extensive research and modeling
Post-closure monitoring
                                      Yes
                                    $0.0430
                                      Yes
                                      Yes
                  Moderate  -  requires research and modeling
Structural integrity inspections
                                      Yes
                                     $11.1
                                      No
                                      No
                        Moderate  -  requires research
Groundwater corrective action
                                      Yes
                                     $19.1
                                      No
                                      No
               High  -  requires extensive research and modeling
Reporting and recordkeeping
                                      No
                                     $27.3
                                      Yes
                                      Yes
                        Low  -  requires extrapolation
Conversion to dry handling
                                      Yes
                                     $57.3
                                      Yes
                                      Yes
               High  -  requires extensive research and modeling
Dewatering and capping costs for inactive impoundments
                                      No
                                     $26.7
                                      No
                                      No
                             No longer applicable
Total (per-ton) disposal costs
          Not directly, but can be calculated using existing analysis
          Not directly, but can be calculated using existing analysis
                            Yes, cost savings rule
                            Yes, cost savings rule
               Can be calculated once updated baseline developed
Fill costs
                                      No
                                      No
                                      No
                                      Yes
                     High  -  requires extensive research


[Federal Register Volume 79, Number 61 (Monday, March 31, 2014)]
[Notices]
[Pages 18112-18113]
[FR Doc No: 2014-07113]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

Notice of Request To Release Airport Property

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice of Intent to Rule on Request to Release Airport Property
at the Sullivan Regional Airport (UUV), Sullivan, Missouri.

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SUMMARY: The FAA proposes to rule and invites public comment on the
release of land at the Sullivan Regional Airport, Sullivan, Missouri,
under the provisions of 49 U.S.C. 47107(h)(2).

DATES: Comments must be received on or before April 30, 2014.

ADDRESSES: Comments on this application may be mailed or delivered to
the FAA at the following address: Lynn D. Martin, Airports Compliance
Specialist, Federal Aviation Administration, Airports Division, ACE-
610C, 901 Locust Room 364, Kansas City, MO 64106.
    In addition, one copy of any comments submitted to the FAA must be
mailed or delivered to: J.T. Hardy, City Administrator, City of
Sullivan, 210 W. Washington, Sullivan, MO 63080,<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Lynn D. Martin, Airports Compliance
Specialist, Federal Aviation Administration, Airports Division, ACE-
610C, 901 Locust Room 364, Kansas City, MO 64106,<PHONE_NUMBER>,
<EMAIL_ADDRESS>The request to release property may be reviewed,
by appointment, in person at this same location.

SUPPLEMENTARY INFORMATION: The FAA invites public comment on the
request to release approximately 20.7 acres of airport property, at the
Sullivan Regional Airport (UUV) under the provisions of 49 U.S.C.
47107(h)(2). On December 26, 2013, the City Administrator of the City
of Sullivan, MO requested from the FAA that approximately 20.7 acres of
property, be released for sale to Aerofil Technology, Inc. for use as a
light packaging, warehousing and distributing operation. On March 14,
2014, the FAA determined that the request to release property at the
Sullivan Regional Airport (UUV) submitted by the Sponsor meets the
procedural requirements of the Federal Aviation Administration and the
release of the property does not and will not impact future aviation
needs at the airport. The FAA may approve the request, in whole or in
part, no sooner than thirty days after the publication of this Notice.
    The following is a brief overview of the request:
    Sullivan Regional Airport (UUV) is proposing the release of one
parcel, containing 20.7 acres. The release of land is necessary to
comply with Federal Aviation Administration Grant Assurances that do
not allow federally acquired airport property to be used for non-
aviation purposes. The sale of the subject property will result in the
land at the Sullivan Regional Airport (UUV) being changed from
aeronautical to non-aeronautical use and release the lands from the
conditions of the Airport Improvement Program Grant Agreement Grant
Assurances. In accordance with 49 U.S.C. 47107(c)(2)(B)(i) and (iii),
the airport will receive fair market value for the property, which will
be subsequently reinvested in another eligible airport improvement
project for general aviation facilities at the Sullivan Regional
Airport.
    Any person may inspect, by appointment, the request in person at
the FAA office listed above under FOR FURTHER INFORMATION CONTACT. In
addition, any person may, upon appointment and request, inspect the
application, notice and other documents determined by the FAA to be
related to the application in person at the Sullivan Regional Airport.

    Issued in Kansas City, MO, on March 21, 2014.
Edward A. Hyatt,
Acting Manager Airports Division.
[FR Doc. 2014-07113 Filed 3-28-14; 8:45 am]
BILLING CODE 4910-13-P


[Federal Register Volume 85, Number 80 (Friday, April 24, 2020)]
[Notices]
[Page 23018]
[FR Doc No: 2020-08767]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. ER20-1600-000]

Cubico Huntley Lessee, LLC; Supplemental Notice That Initial
Market-Based Rate Filing Includes Request For Blanket Section 204
Authorization

    This is a supplemental notice in the above-referenced proceeding of
Cubico Huntley Lessee, LLC's application for market-based rate
authority, with an accompanying rate tariff, noting that such
application includes a request for blanket authorization, under 18 CFR
part 34, of future issuances of securities and assumptions of
liability.
    Any person desiring to intervene or to protest should file with the
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, in accordance with Rules 211 and 214 of the Commission's
Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone
filing a motion to intervene or protest must serve a copy of that
document on the Applicant.
    Notice is hereby given that the deadline for filing protests with
regard to the applicant's request for blanket authorization, under 18
CFR part 34, of future issuances of securities and assumptions of
liability, is May 11, 2020.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with internet
access who will eFile a document and/or be listed as a contact for an
intervenor must create and validate an eRegistration account using the
eRegistration link. Select the eFiling link to log on and submit the
intervention or protests.
    Persons unable to file electronically may mail similar pleadings to
the Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426. Hand delivered submissions in docketed
proceedings should be delivered to Health and Human Services, 12225
Wilkins Avenue, Rockville, Maryland 20852.
    In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (http://ferc.gov) using the
eLibrary link. Enter the docket number excluding the last three digits
in the docket number field to access the document. At this time, the
Commission has suspended access to the Commission's Public Reference
Room, due to the proclamation declaring a National Emergency concerning
the Novel Coronavirus Disease (COVID-19), issued by the President on
March 13, 2020. For assistance, contact the Federal Energy Regulatory
Commission at<EMAIL_ADDRESS>or call toll-free, (886) 208-
3676 or TYY,<PHONE_NUMBER>.

    Dated: April 20, 2020.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2020-08767 Filed 4-23-20; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 79, Number 138 (Friday, July 18, 2014)]
[Rules and Regulations]
[Pages 41900-41904]
[FR Doc No: 2014-16818]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2013-0764; FRL-9913-94-Region-6]

Approval and Promulgation of Air Quality Implementation Plans;
New Mexico; Grant County Sulfur Dioxide Limited Maintenance Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Direct final rule.

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SUMMARY: The Environmental Protection Agency (EPA) is approving a
limited maintenance plan submitted by the State of New Mexico, dated
November 1, 2013, for the Grant County maintenance area for the 1971
sulfur dioxide (SO2) National Ambient Air Quality Standard
(NAAQS). New Mexico submitted this limited maintenance plan to fulfill
the second 10-year maintenance plan requirement, under section 175A(b)
of the Clean Air Act (CAA or the Act), to ensure maintenance of the
1971 SO2 NAAQS through 2025. The EPA is approving the
maintenance plan pursuant to the CAA.

DATES: This rule is effective on September 16, 2014 without further
notice, unless EPA receives relevant adverse comment by August 18,
2014. If EPA receives such comment, EPA will publish a timely
withdrawal in the Federal Register informing the public that this rule
will not take effect.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R06-
OAR-2013-0764, by one of the following methods:
     www.regulations.gov. Follow the on-line instructions.
     Email: Mr. Guy Donaldson at<EMAIL_ADDRESS>Please
also send a copy by email to the person listed in the FOR FURTHER
INFORMATION CONTACT section below.
     Mail or Delivery: Mr. Guy Donaldson, Chief, Air Planning
Section (6PD-L), Environmental Protection Agency, 1445 Ross Avenue,
Suite 1200, Dallas, Texas 75202-2733.
    Instructions: Direct your comments to Docket ID No. EPA-R06-OAR-
2013-0764. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit through www.regulations.gov or
email, information that you consider to be CBI or otherwise protected.
The www.regulations.gov Web site is an ``anonymous access'' system,
which means EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an email
comment directly to EPA without going through www.regulations.gov, your
email address will be automatically captured and included as part of
the comment that is placed in the public docket and made available on
the Internet. If you submit an electronic comment, EPA recommends that
you include your name and other contact information in the body of your
comment and with any disk or CD-ROM you submit. If EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses. For additional
information about EPA's public docket visit the EPA Docket Center
homepage at www.epa.gov/epahome/dockets.htm.
    Docket: All documents in the docket are listed in the
www.regulations.gov index and in hard copy at EPA Region 6, 1445 Ross
Avenue, Suite 700, Dallas, Texas. While all documents in the docket are
listed in the index, some information may be publicly available only at
the hard copy location (e.g., copyrighted material), and some may not
be publicly available at either location (e.g., CBI). To inspect the
hard copy materials, please schedule an appointment with the person
listed in the FOR FURTHER INFORMATION CONTACT paragraph below or Mr.
Bill Deese at<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Ms. Dayana Medina (6PD-L), Air
Planning Section, telephone<PHONE_NUMBER>, fax<PHONE_NUMBER>, email:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Throughout this document, ``we,'' ``us,''
and ``our'' means EPA.

Table of Contents

I. Background
II. Evaluation of New Mexico's Submittal
    A. Has the State demonstrated that Grant County qualifies for
the Limited Maintenance Plan option?
    B. Elements of a Limited Maintenance Plan for SO2
    1. Attainment Emissions Inventory
    2. Demonstration of Maintenance
    3. Monitoring Network, Verification of Continued Attainment, and
New Mexico's Request To Discontinue the SO2 Hurley
Monitor
    4. Contingency Plan
III. Final Action
IV. Statutory and Executive Order Reviews

I. Background

    On September 11, 1978 (43 FR 40412), the EPA designated a portion
of Grant County, New Mexico as a nonattainment area for the 1971
SO2 NAAQS \1\ under Section 107 of the CAA. The area that
was designated nonattainment is located within the Air Quality Control
Region

(AQCR) No. 012, and consists of a 3.5 mile radius surrounding the
former Kennecott Copper Corporation (now called the Chino Mines-Hurley
Facility) and land above 6470 feet Mean Sea Level within an 8 mile
radius of the Hurley Smelter, which is part of the Chino Mines-Hurley
Facility in Hurley, New Mexico. Emissions from this source caused the
violations of the SO2 NAAQS that resulted in the area being
designated nonattainment. EPA approved the attainment SIP for the Grant
County SO2 nonattainment area on May 5, 1982 (47 FR 19332).
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    \1\ 36 FR 8186 (April 30, 1971).
---------------------------------------------------------------------------

    On February 21, 2003, New Mexico submitted a request that the Grant
County nonattainment area be redesignated to attainment for the 1971
SO2 NAAQS. Along with this request, the state submitted a
maintenance plan which demonstrated that the area was expected to stay
in attainment of the 1971 SO2 NAAQS for the initial
maintenance period through 2015. The EPA approved the redesignation
request and the maintenance plan on September 18, 2003 (68 FR 54672).
    Section 175A(b) of the Act as amended in 1990 requires the state to
submit a subsequent maintenance plan covering a second ten-year period
to EPA eight years after designation to attainment. To fulfill this
requirement of the Act, New Mexico submitted the second ten-year update
of the SO2 maintenance plan to EPA on November 1, 2013. The
limited maintenance plan SIP revision demonstrates that the area is
expected to stay in attainment of the 1971 SO2 NAAQS through
2025. The revision also requests to discontinue the only SO2
monitor in the Grant Country maintenance area (the Hurley monitor, AQS
ID 35-017-0003-42401-1) in light of the negligible SO2
concentrations measured at the monitor, and to implement an alternative
SO2 monitoring methodology in its place. This action is
being taken with respect to the 1971 24-hour SO2 NAAQS. This
action does not address the 2010 1 hour SO2 Standard but we
note that concentrations measured on a 1 hour basis are also quite low.

II. Evaluation of New Mexico's Submittal

    On November 1, 2013, the State of New Mexico submitted a revision
to the New Mexico SIP. This revision provides the second 10-year update
to the maintenance plan for the area, as required by the section
175A(b) of the Act. The purpose of this plan is to ensure continued
maintenance of 1971 SO2 NAAQS in Grant County by
demonstrating that future emissions of this criteria pollutant are
expected to remain at or below emission levels necessary for continued
attainment of the 1971 SO2 NAAQS. Since there are few
specific content requirements defined in section 175A of the Act for
maintenance plans, EPA has exercised its discretion to make available
the option of submitting a Limited Maintenance Plan for areas that can
make a demonstration of consistent air quality at or below 85% of the
SO2 NAAQS. EPA has developed guidance memoranda on Limited
Maintenance Plan options that are specific to the ozone, particulate
matter with an aerodynamic diameter less than 10 microns
(PM10), and carbon monoxide NAAQS.\2\ Consistent with EPA's
policy for limited maintenance plans as presented in those guidance
memoranda, EPA here has the authority to exercise its reasonable
discretion and conclude that a limited maintenance plan option is
justifiable and appropriate in this case for the SO2 NAAQS.
New Mexico has opted to develop a Limited Maintenance Plan for the
Grant County SO2 maintenance area to fulfill the second 10-
year maintenance period required by the Act. Our evaluation of the
Grant County SO2 Limited Maintenance Plan is presented
below.
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    \2\ See ``Limited Maintenance Plan Option for Nonclassifiable
Ozone Nonattainment Areas'' from Sally L. Shaver, Office of Air
Quality Planning and Standards, dated November 16, 1994; ``Limited
Maintenance Plan Option for Nonclassifiable CO Nonattainment Areas''
from Joseph Paisie, Office of Air Quality Planning and Standards,
dated October 6, 1995; and ``Limited Maintenance Plan Option for
Moderate PM10 Nonattainment Areas'' from Lydia Wegman,
Office of Air Quality Planning and Standards, dated August 9, 2001.
Copies of these guidance memoranda can be found in the docket for
this proposed rulemaking.
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A. Has the State demonstrated that Grant County Qualifies for the
Limited Maintenance Plan option?

    Following the approach presented in our guidance memoranda, we
believe it appropriate for a limited maintenance plan for
SO2 option to be available for a State that demonstrates
that the design values for SO2 in the maintenance area are
at, or below, 85 percent of the 24-hour SO2 NAAQS or 0.119
parts per million (ppm). To support use of this option, the area's
design value should not exceed the 0.119 ppm threshold throughout the
entire rulemaking process. There is currently only one monitor located
in the Grant County maintenance area, the Hurley, New Mexico monitor
(AQS ID 35-017-0003-42401-1). This monitor has been operating since
1997 and EPA determined in a letter to NMED dated August 26, 2002, that
the Hurley monitor was placed where modeling indicated the highest
SO2 concentrations were likely to occur. For this
submission, the state provided data showing that the SO2
design value for the 24-hour SO2 NAAQS (0.14 part per
million (ppm)) has been 0.0 ppm for each of the five most recent years
(2007-2011) for which certified ambient air quality data is available
for the Hurley monitor. These values are clearly below the 85%
threshold, demonstrating that the Grant County maintenance area is
suitable for a Limited Maintenance Plan option. Consistent with past
contexts where a limited maintenance plan option was deemed to be
available, the area does not have a recent history of monitored
violations nor any long prior history of monitored air quality
problems.

B. Elements of a Limited Maintenance Plan for SO2

    A Limited Maintenance Plan conventionally consists of several core
provisions: An attainment inventory, a demonstration of maintenance of
the NAAQS, operation of a monitoring network, a contingency provision,
as necessary, to promptly correct any violation of the NAAQS.
1. Attainment Emissions Inventory
    The State's plan should include an emissions inventory to identify
the level of emissions in the maintenance area that is sufficient to
attain the NAAQS. The inventory should represent emissions during the
same five-year period associated with air quality data used to
determine whether the area meets the applicability requirements of the
limited maintenance plan option. New Mexico's Grant County Limited
Maintenance Plan submittal includes an SO2 emissions
inventory for Grant County Title V sources and Minor Point sources for
the years 2007-2011. These base years represent the most recent
emissions inventory data available and are consistent with the data
used to determine applicability of the limited maintenance plan option
(i.e., design values at, or below, 85 percent of the 24-hour
SO2 NAAQS). The source that caused the violations of the
SO2 NAAQS that resulted in the area being designated
nonattainment, the former Hurley Smelter, was dismantled and its stacks
removed in July 2006.\3\ The

former Hurley Smelter was the only major source of SO2
located within the maintenance area boundary. There are currently no
major sources of SO2 located in the Grant County maintenance
area. There are currently two Title V sources in Grant County (both
located outside of the Grant County maintenance area): the Chino Mine
and the Tyrone Mine. The combined actual SO2 emissions for
the two sources has been no more than 6.57 tons per year (tpy) for each
of the years 2007-2011. The primary sources of SO2 emissions
for both facilities are blasting fugitives and diesel generator
engines. There are currently four minor point sources located within
the Grant County maintenance area with combined annual allowable
SO2 emissions of 316 tpy for each of the years 2007-2011.
However, the actual SO2 emissions generated by these sources
are minimal. This data supports New Mexico's conclusion that the
control measures contained in the original attainment plan will
continue to protect and maintain the 1971 SO2 NAAQS.
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    \3\ The Hurley Smelter, a copper ore smelter that was part of
the Chino Mine-Hurley Facility located in Hurley, New Mexico, was
dismantled and its stacks were removed in July 2006. The Chino Mine-
Hurley Facility modified its Title V and New Source Review (NSR)
permits to remove all equipment associated with the former Hurley
Smelter. A copy of the revised permit issued on May 23, 2007, is
found in Appendix B of the State's submittal.
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2. Demonstration of Maintenance
    EPA considers the maintenance demonstration requirement satisfied
if the monitoring data show that the area is meeting the air quality
criteria for limited maintenance areas (i.e., design value at or below
0.119 parts per million (ppm) or 85% of the 24-hour SO2
NAAQS). There is no requirement to project emissions over the
maintenance period. Instead, EPA believes that if an area is at or
below 85 percent of exceedance levels, the air quality along with the
continued applicability of PSD requirements, any control measures
already in the SIP, and Federal measures, should provide adequate
assurance of maintenance over the remainder of the 10-year maintenance
period. As discussed above, the state provided data showing that the
SO2 design value for the 24-hour SO2 NAAQS (0.14
part per million (ppm)) has been 0.0 ppm for each of the five most
recent years (2007-2011) for which certified ambient air quality data
is available for the Hurley monitor. These values are well below the
85% threshold, thus demonstrating the appropriateness of a Limited
Maintenance Plan option for the Grant County maintenance area.
    When EPA approves a limited maintenance plan, EPA is concluding
that an emissions budget may be treated as essentially not constraining
for the length of the maintenance period because it is unreasonable to
expect that such an area will experience so much growth in that period
that a violation of the SO2 NAAQS would result.
3. Monitoring Network, Verification of Continued Attainment, and New
Mexico's Request To Discontinue the SO2 Hurley Monitor
    To verify the attainment status of the area over the maintenance
period, the maintenance plan should contain provisions for continued
operation of an appropriate, EPA-approved air quality monitoring
network, in accordance with 40 CFR part 58. Over the course of the last
30 years, New Mexico has operated four SO2 monitors in the
Grant County maintenance area. There have been no monitored exceedances
of the 1971 SO2 NAAQS in the Grant County maintenance area
since 1979. The Hurley monitor (AIRS Monitor ID 35-017-0003-42401-1),
which has been in operation since 1997, is the only SO2
monitor currently operating in the Grant County maintenance area. EPA
determined in a letter to NMED dated August 26, 2002, that the Hurley
monitor was placed where modeling indicated the highest SO2
concentration was likely to occur. Monitored SO2
concentrations have been negligible for the most recent five years for
which certified ambient air quality data is available, following the
July 2006 dismantling of the Hurley Smelter, which was the source
originally responsible for the violations of the SO2 NAAQS
that resulted in the area being designated nonattainment. The state
provided data from the Hurley monitor showing that the SO2
design value for the 24-hour SO2 NAAQS (0.14 part per
million (ppm)) has been 0.0 ppm for each of the five most recent years
(2007-2011) for which certified ambient air quality data was available.
    In light of the limited number of SO2 emission sources,
the limited amount of SO2 emissions, and the negligible
monitored SO2 concentrations in the Grant County maintenance
area, New Mexico is requesting to discontinue SO2 air
monitoring within the maintenance area, as currently required by its
maintenance plan, and to instead implement an alternative
SO2 monitoring methodology that does not utilize a gaseous
analyzer for determining compliance with the SO2 NAAQS. The
alternative SO2 monitoring method will consist of using PSD
and Title V modeling and any required post-construction monitoring for
new and modified air quality permits and an annual emission review of
all major SO2 sources located in the Grant County
maintenance area. In the event that PSD or Title V modeling, PSD or
Title V post-construction monitoring, or the annual emissions review of
major sources within the maintenance area indicate there is a
significant increase in SO2 emissions that may cause a
potential SO2 NAAQS violation, New Mexico will reinstitute a
gaseous SO2 monitor at the Hurley, NM monitoring location
(AIRS ID 35-017-0003-42401-1) or at a site expected to read greater
SO2 levels than this site. If the monitored SO2
values after one year are at or below 50 percent of the 24-hour or
annual SO2 NAAQS, or both, the monitor would again be
removed and the alternative SO2 monitoring methodology
reinstated. The process would be repeated each time PSD or Title V
monitoring, PSD or Title V post-construction monitoring, or the annual
emission review of major SO2 sources within the maintenance
area indicate a potential SO2 NAAQS violation.
    We accordingly find that with the alternative SO2
monitoring methodology in place, the Hurley monitor is no longer
required as part of the 24-hour SO2 maintenance plan. By our
approval, the maintenance plan will not contain any contingency
measures to be triggered by a monitored air quality concentration. NMED
may submit a separate request for a system modification (including a
request for discontinuation of a State or local air monitoring station)
for EPA's review and approval under the bases provided in 40 CFR Sec.
58.14. We find that the State has satisfied the monitoring network and
verification of continued attainment requirements for the limited
maintenance plan.
4. Contingency Plan
    Section 175A(d) of the CAA requires that a maintenance plan include
contingency provisions, as necessary, to promptly correct any violation
of the NAAQS that occurs after the area is redesignated to attainment.
Under section 175A(d), contingency measures do not have to be fully
adopted at the time of redesignation. However, the contingency plan is
considered to be an enforceable part of the SIP and should ensure that
the contingency measures are adopted expeditiously once they are
triggered by a specified event. The general approach for contingency
measures discussed in the limited maintenance plan guidance memoranda
provide that the contingency provisions should identify the measures to
be adopted, a schedule and procedure for adoption and implementation,
and a specific time limit for action by the State. However, the General
Preamble

for the Implementation of Title I of the Act Amendments of 1990 (57 FR
13498) states that SO2 provisions require special
considerations. A primary reason is that SO2 control methods
are well established and understood. Therefore, contingency measures
for SO2 need only consist of a comprehensive program to
identify sources of violations of the SO2 NAAQS and to
undertake an aggressive follow-up for compliance and enforcement.
    There are currently no major SO2 sources within the
Grant County maintenance area. In the event that an SO2
source(s) moves into or within close proximity to the Grant County
SO2 maintenance area, New Mexico will ensure that such
source(s) will comply with all applicable state and federal
SO2 regulations and requirements. New Mexico is also
committing to maintain a comprehensive compliance and enforcement
program to identify sources of violation of the SO2 NAAQS
within the maintenance area and to undertake aggressive follow up
measures to ensure compliance with the SO2 NAAQS. In
conformance with CAA section 175A(d), New Mexico will also implement
all measures with respect to the control of air pollutants concerned
which were contained in the SIP for the area before redesignation of
the area as an attainment area, to the extent such measures are
applicable to any sources which may exist at the time of any NAAQS
exceedance. We believe that New Mexico's contingency plan is adequate
for identifying which SO2 sources are responsible for
violations of the 1971 SO2 NAAQS and undertaking aggressive
measures to ensure compliance of the SO2 NAAQS. We find that
New Mexico's contingency measures plan is approvable.

III. Final Action

    The EPA is taking direct final action to approve the second 10-year
limited maintenance plan for Grant County submitted by the State of New
Mexico.
    We are approving this limited maintenance plan for the Grant County
maintenance area for the 1971 SO2 NAAQS. The State of New
Mexico has complied with the requirements of section 175A of the CAA,
consistent with its interpretation through past limited maintenance
plan guidance provided several EPA memoranda dated November 16, 1994;
October 6, 1995; and August 9, 2001. New Mexico has shown through its
submittal that SO2 emissions in the Grant County maintenance
area have decreased to very low levels following the dismantling of the
Hurley smelter in July 2006. New Mexico has also shown that the
monitored levels of the 1971 SO2 NAAQS in the Grant County
area have been negligible since 2007, with design values of 0 ppm for
the most recent five years for which certified ambient air monitoring
data is available. Thus, the area has been consistently well below the
requisite level of 0.119 ppm for the 24-hour SO2 NAAQS in
order to qualify for the limited maintenance plan option. New Mexico
has also shown that all SO2 monitored values have been
consistently well below the 1971 SO2 NAAQS levels. These low
monitored values of SO2 are expected through the end of the
maintenance period.
    We find that with the alternative SO2 monitoring
methodology in place, the Hurley monitor is no longer required as part
of the 24-hour SO2 maintenance plan. By our approval, the
maintenance plan will not contain any contingency measures to be
triggered by a monitored air quality concentration. NMED may submit a
separate request for a system modification (including a request for
discontinuation of a State or local air monitoring station) for EPA's
review and approval under the bases provided in 40 CFR 58.14.
    EPA is publishing this rule without prior proposal because we view
this as a non-controversial amendment and anticipate no adverse
comments. However, in the proposed rules section of this Federal
Register publication, we are publishing a separate document that will
serve as the proposal to approve the SIP revision if relevant adverse
comments are received. This rule will be effective on September 16,
2014 without further notice unless we receive relevant adverse comment
by August 18, 2014. If we receive relevant adverse comments, we will
publish a timely withdrawal in the Federal Register informing the
public that the rule will not take effect. We will address all public
comments in a subsequent final rule based on the proposed rule. We will
not institute a second comment period on this action. Any parties
interested in commenting must do so now. Please note that if we receive
relevant adverse comment on an amendment, paragraph, or section of this
rule and if that provision may be severed from the remainder of the
rule, we may adopt as final those provisions of the rule that are not
the subject of an adverse comment.

IV. Statutory and Executive Order Reviews

    Under the Clean Air Act, the Administrator is required to approve a
SIP submission that complies with the provisions of the Act and
applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a).
Thus, in reviewing SIP submissions, EPA's role is to approve state
choices, provided that they meet the criteria of the CAA. Accordingly,
this action merely proposes to approve state law as meeting federal
requirements and does not impose additional requirements beyond those
imposed by state law. For that reason, this action:
     Is not a ``significant regulatory action'' subject to
review by the Office of Management and Budget under Executive Order
12866 (58 FR 51735, October 4, 1993);
     does not impose an information collection burden under the
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
     is certified as not having a significant economic impact
on a substantial number of small entities under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.);
     does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Public Law 104-4);
     does not have federalism implications as specified in
Executive Order 13132 (64 FR 43255, August 10, 1999);
     is not an economically significant regulatory action based
on health or safety risks subject to Executive Order 13045 (62 FR
19885, April 23, 1997);
     is not a significant regulatory action subject to
Executive Order 13211 (66 FR 28355, May 22, 2001);
     is not subject to requirements of section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272
note) because application of those requirements would be inconsistent
with the CAA; and
     does not provide EPA with the discretionary authority to
address, as appropriate, disproportionate human health or environmental
effects, using practicable and legally permissible methods, under
Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, this proposed rule does not have tribal implications as
specified by Executive Order 13175 (65 FR 67249, November 9, 2000),
because the SIP is not approved to apply in Indian country located in
the state, and EPA notes that it will not impose substantial direct
costs on tribal governments or preempt tribal law.
    The Congressional Review Act, 5 U.S.C. section 801 et seq., as
added by the Small Business Regulatory Enforcement Fairness Act of
1996, generally provides that before a rule

may take effect, the agency promulgating the rule must submit a rule
report, which includes a copy of the rule, to each House of the
Congress and to the Comptroller General of the United States. EPA will
submit a report containing this rule and other required information to
the U.S. Senate, the U.S. House of Representatives, and the Comptroller
General of the United States prior to publication of the rule in the
Federal Register. A major rule cannot take effect until 60 days after
it is published in the Federal Register. This action is not a ``major
rule'' as defined by 5 U.S.C. section 804(2).
    Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by September 16, 2014. Filing a petition for
reconsideration by the Administrator of this final rule does not affect
the finality of this rule for the purposes of judicial review nor does
it extend the time within which a petition for judicial review may be
filed, and shall not postpone the effectiveness of such rule or action.
This action may not be challenged later in proceedings to enforce its
requirements. (See section 307(b)(2).)

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by
reference, Reporting and recordkeeping requirements, Sulfur oxides.

    Dated: July 7, 2014.
Ron Curry,
Regional Administrator, Region 6.

    40 CFR part 52 is amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

Subpart GG--New Mexico

0
2. In Sec.  52.1620(e) the second table titled ``EPA Approved
Nonregulatory Provisions and Quasi-Regulatory Measures in the New
Mexico SIP'' is amended by adding the entry ``Second 10-year
SO2 maintenance plan for Grant County'' at the end of the
table to read as follows:

Sec.  52.1620  Identification of plan.

* * * * *
    (e) * * *

            EPA Approved Nonregulatory Provisions and Quasi-Regulatory Measures in the New Mexico SIP
----------------------------------------------------------------------------------------------------------------
                                    Applicable         State
                                  geographic or     submittal/
     Name of SIP provision        nonattainment      effective        EPA  approval date           Comments
                                       area            date
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
Second 10-year SO[ihel2]        Portion of Grant      11/1/2013  7/18/2014..................
 maintenance plan for Grant      county.                         [Insert FR citation].......
 County.
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[FR Doc. 2014-16818 Filed 7-17-14; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register Volume 77, Number 200 (Tuesday, October 16, 2012)]
[Notices]
[Page 63308]
[FR Doc No: 2012-25397]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Notice of Commission Staff Attendance

    The Federal Energy Regulatory Commission (Commission) hereby gives
notice that members of the Commission's staff may attend the following
meeting related to the transmission planning activities of the Southern
Company Services, Inc.

Southeastern Regional Transmission Planning Process (SERTP) Interim
Stakeholders' Meeting on Order No. 1000

    October 17, 2012, 9:00 a.m.-3:00 p.m., Local Time.
    The above-referenced meeting will be held at: Atlanta Airport
Marriott, Atlanta Georgia.
    The above-referenced meeting is open to stakeholders.
    Further information may be found at: www.southeasternrtp.com.
    The discussions at the meeting described above may address matters
at issue in the following proceedings:
    Docket No. ER12-337, Mississippi Power Company.
    Docket No. ER12-2521, Louisville Gas and Electric Company and
Kentucky Utilities Company.
    For more information, contact Valerie Martin, Office of Energy
Market Regulation, Federal Energy Regulatory Commission at (202) 502-
6139 or<EMAIL_ADDRESS>
    Dated: October 10, 2012.
Kimberly D. Bose,
Secretary.
[FR Doc. 2012-25397 Filed 10-15-12; 8:45 am]
BILLING CODE 6717-01-P