Chapter 8
Other Configurations and Fuels

Contents
8.1	General	2
8.2	Combined Heat and Power and Industrial Cogeneration	2
8.3	Biomass	9

General
One commenter (9471) stated that the proposed standards do not account for combined cycle units that have a two-on-one or three-on-one configuration that may operate while one combustion turbine is out of service for maintenance, which reduces efficiency due to reduced heat input into the steam cycle. Though the mass emissions may decrease during this mode of operation, the lbs CO2 /MWh will increase, resulting in a violation of the standard despite the lower total emissions.
One commenter (10693) stated that EPA should not exempt power plants that combust solid waste, which contains a diverse mix of waste materials, some benign and some very toxic including trace metals and trace organics. Additionally, landfill gas consists primarily of carbon dioxide, methane, and non-methane organic compounds.
The purpose of this rulemaking is to establish CO2 standards for fossil fuel-fired EGUs. Municipal waste combustors have not been typically included in this source category. Therefore, even if one of those units meets the general heat input and electric sales criteria, we are not finalizing CO2 emission standards for municipal waste combustors subject to subpart Eb of 40 CFR part 60.
Combined Heat and Power and Industrial Cogeneration
Citing the environmental benefits and efficiency of adding cogeneration to an industrial steam system and generating electricity from excess steam, one commenter (9201) agreed with EPA's proposal to exempt most industrial cogeneration units.
The intent of this rulemaking is to cover utility CHP units since they serve essentially the same purpose as electric-only EGUs (i.e., the sale of electricity to the grid), but not industrial CHP units since they serve a different primary purpose (i.e., providing useful thermal output with electric sales as a byproduct). Based on public comments and after further analysis, the EPA makes two adjustments to the definition of applicability of this rule to CHP units. See section III.D.2 of the final rule preamble.
Several commenters (1898; 8994; 8952; 9002; 9503; 9665; 9592; 10682; 9201; 10038; 10095; 10239; 10869) stated they were strong supporter of CHP plants and approved of EPA's support of CHP sources and their increased deployment and excluding them from the emission standards.
Commenter (10095) stated that they support EPA specifically providing CHP facilities a 5% credit for avoided energy loss in the transmission of electricity.
Two commenters (8944, 8952) stated that while recognizing that the proposed provisions for CHP reward the higher efficiency, the commenters stated the industry would be far better served and incentivized through an exemption of the technology from the proposed rule.

Two commenters (9194; 9592) supported excluding CHP units that generate greater than 25 MWs with an overall efficiency greater than 70%. According to the commenter, CHP units have been built by several utilities and have provided combined heat and power energy with equivalent CO2 emissions well below the proposed standard. It would be counterproductive to subject these units to a GHG NSPS standard.

One commenter (9665) believes that the agency should exempt from the GHG NSPS new CHP facilities that achieve a system efficiency of 75% (lower heating value) or higher regardless of how much electricity it supplies to the grid.  According to the commenter, an exemption would not create a regulatory loophole as any CHP facility that could achieve a system efficiency of 75% would easily meet the proposed emission limits. The benefit to a qualifying facility would be avoided time and expense of monitoring, recordkeeping, reporting, etc.

One commenter (8952) stated that by not exempting CHP units, the proposed rule incentivizes the development of capacity that will remain outside the current grid system. The commenter stated that it would be a burden on the end-user to catalog each unit of thermal energy reduced or estimate the resistive losses in the transmission system. Because the rule would only apply to grid-connected generation, the rule could cause CHP facilities to not connect to the grid system so as not to be captured by this requirement. This would result in the additional negative consequence that CHP facilities deny their capacity to the grid foregoing their potential role as system support in unusual events.

Several commenters (10098, 10085, 9733, 10239) stated that given their energy efficiency and environmental benefits and the fact that the Administration is actively promoting CHP in other contexts, EPA should exclude CHP units from the rule.

One commenter (7990) recommended that the Proposed Rule be modified to establish a reasonable level of CHP efficiency.

One commenter (10098) stated that for EPA to impose regulations here that could discourage new facilities. At a minimum, if EPA regulates CHP, it must fully recognize the benefits it offers by applying an appropriate discount for avoided electricity losses through transportation and by counting all thermal energy toward gross energy output.

Several commenters (9733, 10098, 10239) stated that if EPA maintains, however, that industrial, commercial, and institutional CHP units should be included under the rule, the commenters supports the Agency's proposal to apply a discount for avoided electricity losses through transmission. However, based on data from the U.S. Energy Information Administration, the discount should be increased from 5% to 7%.

One commenter (9733, 9002) stated that the final rule should exempt all CHP units where useful thermal output accounts for at least 20 percent of the total useful output as EPA had considered in its April 2012 proposed rule.  According to commenter 9733, the lower emission rates for CHP facilities means that new CHP boilers and new turbines will already meet subpart D/KKKK/TTTT requirements. With the right policy and economic conditions, CHP can represent a significant portion of U.S. electric capacity. In 2008, the Department of Energy's Oak Ridge National Laboratory calculated that if CHP provided 20 percent of U.S. electric capacity, carbon emissions could be reduced by more than 800 million metric tons (MMT) per year. In this 20 percent scenario, over 60 percent of the projected increase in CO2 emissions between now and 2030 could be avoided.

The commenter (9733) stated that by exempting CHP facilities meeting the proposed power and thermal energy minimum outputs, EPA would provide incentives for new generation facilities to consider co- locating at manufacturing and other steam hosts and to develop highly-efficient CHP, as opposed to stand alone power generation. Such an exemption would provide a positive precedent for EPA's guidelines for state plans for existing facilities under CAA section 111(d) as well as for policy makers who are continuously examining their policies to incentivize CHP.

The commenter (9733) stated that if EPA does not exempt all CHP units from, it should at least exempt industrial units as fundamentally different than EGUs. While the commenter does not agree with the proposal to continue to subject non-utility units to other aspects of the standard of performance, such as recordkeeping, and relieving them only of their obligation to meet the emission limits, the commenter does appreciate that EPA is recognizing the distinctions between industrial and utility combustion turbines. The commenter stated that EPA should continue to make those distinctions in its EGU regulations, as appropriate, and that EPA's recognition of the distinction supports exempting industrial CHP units from regulation.

One commenter (10239) stated that in recognition of the benefits that CHP units offer, the DOE has adopted a number of initiatives to promote industrial distributed energy in the United States, and the Administration has set a national goal of increasing CHP deployment by 40 gigawatts (50%) by 2020. Exempting entirely industrial CHP units will promote adoption of efficient, reliable, and low-emission distributed generation. Because industrial CHP units must meet source-specific needs, the balance of thermal energy and electricity production vary and may shift over any given time period making calculation of thermal energy equivalence (conversion to kWh) extremely challenging for reporting and enforcement purposes. Regulation is further complicated by the use of third party-owned CHP units at adjacent industrial facilities. EPA also failed to assess whether industrial CHP units could meet the proposed standards relying instead on a hypothetical example of a CHP. EPA should exclude industrial CHP units from Section 111 until it can determine how CHP units could calculate their GHG emissions under real-world conditions and how the proposed emission limitation would impact those units.

One commenter (10239) stated that if EPA does not exempt all CHP units, EPA should exempt CHP units whose primary purpose is not the production of electricity for sale in the retail market. Industrial CHP facilities provide thermal energy and, to a lesser degree, electric energy for internal facility operations and are typically designed to maximize thermal energy output. The electric output to a utility power generation system is limited to residual electric power that cannot be used by the facility. The production of such electricity is not the primary purpose of the CHP unit. The EPA should recognize that these facilities are not fossil fired EGUs and exclude them from the subcategories to which the proposed rule applies. To provide greater certainty for facilities, the commenter urged EPA to adopt a quantitative test that ensures that industrial CHP units used for manufacturing or oil and gas facilities are excluded from fossil fuel-fired EGU subcategories.

One commenter (10239) stated that using a variety of methods, EPA could exclude from this rulemaking:
   * Any CHP facility that supplies less than two thirds of its net combined thermal and electric output to a utility power generation distribution system or to a utility steam system distribution system on an annual MMBtu basis.
   * CHP units that simultaneously produce power and heat and, at the time the unit is placed into service, have an energy savings of 10% or more when compared to units that produce heat and power separately.
   * CHP facilities based on Standard Industrial Classification or other codes to distinguish between the EGUs that are subject to the NSPS and manufacturing and oil and gas facilities that are excluded from it.
   * CHP units that have total thermal energy production that approaches or exceeds the unit's electricity production.
   * Industrial CHP units by fuel type. For example, the EPA could exempt all industrial CHP unit that are fired predominantly with biomass, are fired with gaseous fuels (i.e., pipeline, natural, field, and refinery fuel bases).

One commenter (9774) stated that the potential applicability of the rule to CHP units creates a significant disincentive for new projects that would only be viable if they sell electricity to the grid. Applicability of the NSPS standard may also result in the loss of current CHP capacity. The commenter gave an example of a facility that currently operates solid fuel fired fluidized bed boilers to generate electricity and to supply thermal heat to nearby industry. CCS cannot be expected to be cost-effective for this type of electric supplier. Currently, the proposed regulation would likely prohibit the facility from replacing these units using the same fuels in the future. The result may be that the facility discontinues operation instead of efficiently providing power and heat to end-users at lower CO2 rates than can be achieved by separated dedicated power systems serving each need. The commenter stated that EPA should exclude efficient CHP from regulation under the proposed NSPS rule. Exempt CHP could potentially be defined as projects achieving a 75% overall efficiency although the appropriate level should be further evaluated. This recommended approach will actually encourage the addition of CHP electricity to the grid.

One commenter (9002) stated that the proposal appropriately does not cover the forest products industry CHP units. This is appropriate due to the substantial energy efficiency and avoided GHG emission benefits provided by this industry's CHP units.

One commenter (10554) stated that CHP facilities should be subject to the same requirements as electric-only generators under any NSPS for GHGs. The CO2 standard of performance should apply to all systems including CHP facilities that supply more than one-third of their energy output as electricity.

One commenter (9503) urged EPA to add a fourth criterion for excluding CHP facilities for CHP facilities that are highly efficient. This exclusion could make use of the definition of CHP already set forth in the Proposed Rule, and include an efficiency benchmark. The commenter's recommendation is to set the benchmark for highly efficient at 65 percent or greater overall plant efficiency, including thermal, mechanical and electric output. The reason is that this number is in use by several federal and state policies aimed at promoting efficient CHP.

One commenter (8952) prefers to exempt a SC turbine, the prime mover in the CHP.

One commenter (8918) stated that given the infinite potential heat-to-power ratios of CHP facilities, the equivalency approach used by EPA may limit the development of CHP facilities because the approach cannot fairly assess all of the potential ratio configurations and requires that a separate heat and power base case be developed. In many cases, an accurate base case cannot be established. Lastly, the EPA's equivalency approach is predicated on the assumption that the steam host would have installed new equipment subject to a NSPS.
See section III.D.2 of the final rule preamble for the EPA's response to this comment.
One commenter (9042) agreed that an affected facility should be able to use its non-emitting energy generation to comply with the emission standards. They suggested that EPA also consider allowing affected facilities to utilize their off-site non-emitting energy generation to comply with the emission standards to the extent that it can be quantified and verified.
 The final rule permits the use of integrated non-emitting technologies as a means of reducing emission rates.
One commenter (9733) stated that two recent distributed generation rules use different approaches than the 50% credit for thermal output used by the FERC and the 1997 utility NSPS. Stating that CHP is more environmentally beneficial than the existing NSPS approach, the commenter recommended the Regulatory Assistance Project (RAP) approach using information such as the desired standard, total emissions, thermal emissions and electric output.  They stated that one benefits of this approach is that CHP units that produce primarily electricity would have to operate at an input-based emissions rate that is close to what utility units must achieve. CHP units producing primarily thermal output would be able to operate at an input-based emissions rate that is close to what industrial boilers must achieve.
Based on further consideration and review of the comments submitted, the EPA is finalizing 100 percent credit for useful thermal output for all newly constructed, modified, and reconstructed CHP sources. Full credit for useful thermal output appropriately recognizes the environmental benefit of CHP. See sections III.F.2 and III.D.2 of the final rule preamble.
One commenter (9733) stated that they are very concerned about the precedent of a 75% factor for useful thermal output. Congress is considering an overhaul of tax incentives for clean energy and is deliberating whether CHP should receive tax credits, and whether and how to credit CHP thermal output. Congress likely will look to the final rule as an important precedent on this subject. Further, there are 42 states with either a Renewable Portfolio Standard (RPS) or an Energy Efficiency Resource Standards (EERS), 21 allow CHP to be used for compliance. CHP supporters continually are seeking to expand CHP opportunities in other states. EPA is well aware of these efforts and agency staff have helped provide technical resources to further the education of participants engaged in the legislative deliberations. It makes no sense for EPA to support these efforts on the one hand, but then to set an adverse national precedent for CHP on the other.
See Response 8.2-4 for the EPA's response to this comment.
One commenter (10682) stated that the vast majority of CHP projects will not be subject to the rule. The standard only applies to a facility that supplies more than one-third of its potential electricity output and more than 219,000 MWh net electric output to the grid per year. Net electric output excludes power purchased by the facility during the year. As EPA recognizes, CHP systems are often owned and operated by third-party developers, who are distinct from the thermal host. This arrangement is necessary because of the substantial upfront cost and ongoing maintenance responsibilities for a CHP or WHP system. The commenter supports EPA's proposed solution of clarifying that applicability of the rule will be based on gross electric sales to the utility minus purchased power of the thermal host facility. This recognizes the reality that such sales do not constitute sales to the grid.
One commenter (10095) stated they also support EPA's intent to subtract purchased power of adjacent facilities in calculating the 219,000 MWh applicability criteria threshold for CHP facilities. In order to subtract the purchased power of adjacent facilities, the commenter believes it is EPA's intent not to require the direct transmission of electricity to the adjacent facility. EPA needs to provide clarification regarding this calculation.

One commenter (10095) stated that CHP facilities will potentially be dependent on third parties for applicability and compliance determinations. Due to uncontrollable third party risks, EPA needs to provide flexibility to CHP facilities in the event an adjacent facility stops purchasing electricity and/or thermal output or has an outage/malfunction. For example, if an issue arises with a CHP facility's electricity and/or thermal off-taker, EPA should allow the CHP facility time to find a new off-taker or reconfigure the facility prior to making applicability and/or compliance determinations.
Based on public comments and after further analysis, the EPA makes two adjustments to the definition of applicability of this rule to CHP units. See section III.D.2 of the final rule preamble.
One commenter (10681) supports that an appropriate thermodynamic calculation be made to determine the useful energy used rather than a simplified approach based on what could be possible. The thermodynamic calculations for each CHP plant can be submitted in a report to the permitting authority for review. The report would propose the equations and justifications supporting thermal energy used and thermal energy lost. The report and the calculation methodology would then be approved for use by the owner/operator of the unit. Simplified methods will provide a disincentive to a CHP facility or cogeneration facility from taking maximum benefit of the steam produced or energy contained in hot flue gases.
 The EPA believes the final calculation is adequate.  See final preamble.
Several commenters (8918; 8972; 9503; 9665; 8972; 10038; 10682) stated that they encourage EPA to account for and encourage useful heat output from CHP and recommended that the rule should increase the thermal credit from 75 to 100% to account for all of the useful thermal output from a combined heat and power or waste heat to power system. One commenter (9665) stated that no reasons are given to limit to 75 percent the amount of useful thermal output that facilities can count towards its gross energy output, despite allowing 100% of electric and mechanical output to be counted. EPA also solicits comment on whether the thermal "discount should instead be set "on a range of two-thirds to three-fourths." According to commenter 9665, EPA has offered no justification for why thermal output should be discounted at all. According to commenter 9665, anything less than 100% under values the true efficiency of the facility and runs counter to EPA's goal of maximizing energy efficiency.
Multiple commenters (9733, 10239) stated that they oppose the provision that would only count 75% of the useful thermal output of CHP units and if EPA does regulate CHP units, they should count 100% of useful thermal output for compliance determinations.

One commenter (9733) stated that it is unclear why EPA discounted useful thermal output. EPA may have relied on previous CAA rulemakings in which it was concerned about so-called "sham" CHP. The commenter stated that EPA had noted that the Federal Energy Regulatory Commission (FERC) provided only a 50% credit for thermal output for "Qualifying Facilities." EPA may have believed that FERC was attempting to dissuade "sham CHP" units by not providing overly generous benefits to them. If EPA included a 75% factor to help prevent "sham" CHP units, the Proposal already has such provisions. First, to qualify as a CHP unit, 20% percent of the total gross useful energy output must consists of useful thermal output. Further, proposed section 60.4373(d) requires that "[i]f the affected stationary combustion turbine is a CHP stationary combustion turbine, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy." By requiring continuous monitoring, this provision should help preclude so-called "sham" CHP.

One commenter (10239) stated that EPA recognizes that this may be incorrect and seeks comment on the appropriateness of crediting a range of two-thirds to three-fourths of the useful thermal output in the final rule. The commenter does not believe that any discount is appropriate. The commenter stated that the 2006 NSPS for Stationary Combustion Turbines awarded a full (100%) thermal credit and several states have awarded a 100% thermal credit. The EPA is aware of this precedent. The Proposed Stationary Combustion Turbine Rule favorably cited Texas' permit-by-rule regulation, which gives facilities 100% credit for steam generation thermal output. Second, the Associations agree that a discount for avoided electricity losses through transmission and distribution is warranted. However, as a practical matter, average national transmission and distribution losses are closer to 7%. Thus, if the EPA includes CHP in the final rule, the Associations urge EPA to increase the discount factor from 5% to 7%.

One commenter (7990) recommends that EPA align its regulation with the CHP performance standard under the Public Utility Regulatory Policies Act (PURPA) program, which uses a thermal discount factor of 0.5 for thermal energy output.
See Response 8.2-4 for the EPA's response to this comment.
Several commenters (9503, 8972, 9665, 10682) favor increasing the line loss credit for CHP. Commenters (8972-180; 9503-6748) stated that the proposed line-loss credit does not accurately reflect avoided line losses and suggested that, based on information from the EIA, it be increased to 7 percent to reflect national average line losses. One commenter (9665; 10038) stated that EPA should increase the credit from 5 percent to 6 percent to reflect EIA's estimated national average line losses. The commenter (9665) stated that EPA does not explain why 5 percent is an appropriate credit in light of EIA's estimate and other studies that estimate losses at times to be as much as three times higher than the national average. One commenter (8918) urges EPA to continue to recognize this benefit with its transmission factor in the proposed NSPS.
One commenter (7990) stated that the transmission and distribution (T&D) loss factor should apply only to the electricity used on-site. The electricity supplied to the grid should not be discounted as this exported electricity will experience T&D losses similar to other central station power generation.
CHP units are located closer to load centers than remote non-CHP EGUs. This final rule only includes CHP units that sell a significant portion of their potential electric output to the grid. While it is not possible to precisely identify the line loss benefits, but 5 percent is a reasonable approximation.
One commenter (10681) questioned the including an adjustment factor for avoided line losses. Being able to account for avoided line losses only makes sense when it is legally possible for a plant with a CHP unit to utilize net metering. If EPA wants to further encourage, CHP, it could draft this rule to allow for the avoided line loss adjustment in states where large-scale (in terms of 10s of MWs) net metering is allowed.
The line loss credit accounts for CHP units being located close to electric load centers, thus avoiding transmission losses. It is not related to net metering.
One commenter (9665) supports EPA's proposal to amend the definition of "net electric output" to ensure that third-party CHP developers are treated the same as CHPs and adjacent "thermal host" facilities that are under common control. The commenter agrees that this addresses an existing inequity found in the existing NSPS and would serve to further promote additional installations of CHP facilities.
The EPA appreciates the support of the commenter.
One commenter (9665) recommends that EPA revise the definition of "potential electric output," to allow CHP facilities to determine their potential electric output based not just on a unit's "maximum design heat input capacity," but on its total system efficiency. Such an approach would reward units that maximize the efficient use of their fuel inputs and encourage others to do the same. Under the current definition, there is no incentive for facilities to improve overall system efficiency.
See Response 8.2-6 for the EPA's response to this comment.
One commenter (10682) was very supportive of CHP and Waste Heat to Power (WHP) as cleaner, more cost-effective and more efficient alternatives to traditional power generation. The commenter stated that maximizing waste heat capture and use from power generation (CHP) and industrial operations (WHP), and improving supply-side energy efficiency, including both CHP and WHP, can reduce power sector greenhouse gas emissions while at the same time saving families and businesses money, cutting co-pollutant emissions, stimulating local economies, and creating jobs. Mobilizing demand-side energy efficiency, expanding renewable energy generation and shifting use to cleaner generation sources similarly offer significant potential to reduce emissions from conventional power plants. The commenter recommended that EPA adopt a system-wide approach to carbon reduction from existing power plants reflecting the full range of solutions that can secure meaningful and cost-effective emissions reductions. The commenter cited the findings from a 2008 DOE study quantifying the environmental benefits of an increasing the presence of CHP and WHP capacity. The commenter provided examples of how CHP plants have both provided power to the grid and steam to nearby industrial plants.
In making reference to carbon reduction from existing power plants, the comment appears to address the proposed carbon pollution emission guidelines for existing EGUs (79 FR 34830, June 18, 2014) rather than the proposed standards of performance for GHG emissions from new EGUs. As such, a response is not provided here as this comment is outside the scope of this rule.
Biomass
Several commenters (9409; 9733; 9425; 10031; 10045; 10095; 10052; 11056) supported treating emissions from biomass differently than fossil fuels including exempting emissions from the combustion of biomass.
One commenter (9733) stated that based on the GHG avoidance from the use of forest products manufacturing residuals, EPA should not regulate biogenic CO2 emissions from the combustion of biomass in affected CHP units.  The commenter recommended that EPA clarify that the rule is intended to exclude all biogenic CO2 associated with burning biomass under the NSPS until EPA has completed its science review of biogenic CO2 emissions. The commenter provided references to characterize the benefits of using biomass residuals for energy production, including the NCASI study providing evidence of the impact of using residual biomass as fuel versus their disposal on global warming. They stated that disposal will produce more GHG than using the residuals for energy production.
One commenter (9425) stated that in setting standards for units burning natural gas, EPA must recognize that a unit converted to gas from coal or oil will not be physically capable of meeting the same standards as a new, green-field natural gas unit.  Conversion to lower carbon intensive and/or carbon neutral fuels is being considered within our industry as an option to meet other non-GHG regulations.  New NSPS GHG standards should not discourage conversions to these other fuels.  The commenter specifically requested that biomass be exempted and considered a carbon neutral fuel.
One commenter (10031) stated that EPA should continue to exempt biomass-fired units from the standards in the rule. Moreover, EPA should develop an approach for crediting new units that co-fire with biomass, thereby equitably accounting - in the final rule - for the amount of CO2 sequestered by the applicable biomass fuel.
One commenter (10095) stated that they support EPA's proposal that an EGU that primarily fires biomass would not be subject to the proposed CO2 emissions standards. This exclusion incentivizes the use of biomass; however, EPA should further incentivize its use by excluding all biogenic CO2 emissions from an affected facility's compliance calculation. Such an exclusion is consistent with 40 C.F.R. part 98 (the mandatory GHGRP) which requires separate reporting of CO2 emissions from fossil fuels and biogenic sources. EPA should allow the use of the 40 C.F.R. part 98 calculation methodologies to determine a unit's biogenic CO2 emissions for compliance with this proposal to be consistent with the metric tons of CO2 that the unit will report to EPA under 40 C.F.R. part 98. Indeed, [a] long standing inventory convention adopted by the IPCC, the UNFCCC [United Nations Framework Convention on Climate Change], the U.S. GHG Inventory, and many other reporting programs is separate treatment of emissions of CO2 from combustion of biomass and biomass-based fuels from emissions of CO2 from the combustion of fossil-based products.
One commenter (10045) stated that emissions of Crop-Derived CO2 and any indirect CO2 emissions associated with production and gathering of crop residues as EGU fuel are harmless to the global warming process and, therefore, emissions of Crop-Derived CO2 must be excluded from compliance determinations under the instant NSPS once finalized. The commenter (10045) stated that they analyzed the changes in atmospheric CO2 for four different industries: corn wet milling, corn dry milling, corn stover combustion, and wastewater treatment. For the industries studied, the changes are all positive, i.e., the cumulative effect of processing biogenic carbon at these facilities is to reduce atmospheric CO2 levels. As part of their submittal, the commenter provided details of these analyses.
One commenter (9676) stated that EPA cannot on the one hand defer regulation of biogenic emissions under the Tailoring Rule because of the necessity to study the science while on the other hand adopt a regulation that draws an arbitrary limit on how much fossil fuel can be used at an affected facility under NSPS.
One commenter (9409) stated that as the focus of the proposal is fossil fuel-fired electric utility steam generating units and stationary combustion turbines, biomass-fired EGUs do not fit within either of the source categories that EPA seeks to regulate here. Subpart Da applies only to EGUs that combust minimum quantities of fossil fuels and biomass-fired EGUs fall outside of the applicability requirements of subpart KKKK. Supra, biogenic CO2 emissions are distinct from fossil fuel CO2 emissions because biomass is part of the natural carbon cycle and the carbon emitted from biomass-fired EGUs is rapidly cycled between atmospheric and terrestrial carbon pools. Given these important distinctions, there is no basis to expand these source categories to include biomass-fired facilities in this proposed rule. Also, it would be premature for EPA to impose standards on biomass-fired EGUs under any source category at this time because EPA is still in the process of developing a policy for how, if at all, it will account for biogenic CO2 emissions in regulations designed to reduce atmospheric GHG concentrations.

International and domestic regulators also have consistently recognized that biogenic CO2 emissions have no net impact on atmospheric CO2 concentrations. Until EPA completes this process and issues a final rule addressing how to account for biogenic CO2 emissions, the Agency simply has no scientific or technical basis on which to set standards of performance for CO2 emissions from biomass-fired EGUs.

One commenter (9409) stated that EPA's proposed Tailoring Rule directed that sources should rely on EPA's GHG Inventory to calculate a source's GHG emissions. The GHG Inventory does not count CO2 emissions from combustion of biomass at stationary sources. The final Tailoring Rule reversed course to regulate biogenic and fossil CO2 emissions in the same manner. The commenter has petitioned EPA to reconsider the Tailoring Rule's treatment of biomass combustion. EPA granted petition for reconsideration of its biogenic policy. EPA's decision to reconsider its Tailoring Rule appropriately was met with broad endorsement by the Obama Administration. EPA is conducting a thorough scientific review of the climate impacts of biogenic CO2 emissions and plans to develop a new regulatory approach to biogenic CO2 emissions.

One commenter (9409) described the uncertainty resulting from the proposed NSPS for sources using or considering using biomass as fuel. EPA's proposal to treat biogenic and fossil CO2 emissions from co-firing EGUs in the same manner raises significant uncertainty for existing facilities that may consider co-firing biomass in the future and has the potential to foreclose any further expansion of biomass co-firing at coal-fired EGUs. The commenter stated that until EPA establishes GHG standards for modified and reconstructed sources, fossil fuel-fired EGUs that make changes to accommodate co-firing of biomass will be at risk of triggering the proposed GHG emissions limits. The uncertainty caused by such a provision could, as a practical matter, deter any expansion of biomass co-firing until the regulatory status of modified sources is clarified. Treating biogenic and fossil CO2 emissions in the same manner will mask the GHG emission benefits that co-firing with biomass can offer. The commenter also summarized the events surrounding EPA's deferred application of PSD and Title V to biogenic CO2 emissions for three years to allow a scientific review of biogenic CO2 emissions and the court challenges to that deferral.
 One commenter (9409) stated that EPA and the states should incorporate, to the fullest extent possible, the GHG emission mitigation benefits that biomass has to offer in forthcoming existing source NSPS rules. Recognizing the potential climate benefits, the commenter urges EPA to account for the role that biomass energy can play in reducing net GHG emissions, both at a facility-by-facility level through co-firing with fossil fuels and at a broader utility or state level through construction of biomass-fired EGUs in lieu of fossil fuel-fired EGUs. The commenter stated that policies that promote additional afforestation or reforestation increase the amount of land that is actively sequestering carbon from the atmosphere. Wood products store carbon throughout the entire life of the product, and in many cases, they can be substituted for more carbon intensive alternatives, such as concrete or steel. Thus, promoting a strong and healthy forest products industry is an effective way of reducing net GHG emissions. As it develops standards, regulations, or guidelines to address GHG emissions from existing sources under Section 111(d), the commenter urges EPA to work closely with the USDA and in particular the U.S. Forest Service to ensure that it fully and appropriately incorporates the GHG mitigation benefits of forest biomass. The commenter also urges EPA to accommodate and promote existing state programs that recognize the climate benefits of forest biomass.
 Some commenters (10119; 10693) do not support the combustion of biomass for electricity generation nor an exemption of biomass-fueled power plants.
One commenter (10119) stated that even if net biogenic carbon cycle effects are taken into account, emissions from biomass power plants can increase atmospheric CO2 concentrations for decades to centuries depending on feedstocks, biomass harvest practices, and other factors. Multiple studies have shown that it can take a very long time to discharge the "carbon debt" associated with bioenergy production, even where fossil fuel displacement is assumed, and even where "waste" materials like timber harvest residuals are used for fuel. One study, using realistic assumptions about repeat bioenergy harvests of woody biomass, concluded that the resulting atmospheric emissions increase may even be permanent. EPA thus cannot assume that "biogenic" CO2 emissions have no effect on the climate. "Biogenic" and fossil CO2 are indistinguishable in terms of their atmospheric forcing effects. Rather, a full and scrupulously accurate life-cycle analysis is essential to understanding the greenhouse gas implications of burning biomass for energy.
One commenter (10693) stated that the environmental and health impact of biomass power is directly related to the feedstock from which the energy is derived. For example, urban waste, such as construction or demolition debris, is usually inexpensive relative to other biomass feedstocks, and combusting this debris at a biomass plant diverts it away from landfills. However, such waste may be of low-quality, meaning that more feedstock is required to produce a given amount of electricity, or contain high-levels of impurities, resulting in greater air emissions. Biomass combustion increases the risk of the emission of noncarbon air pollutants releasing many of the same air pollutants as fossil-fuel generation, although the quantities may differ substantially on per MWh basis. Without controls, combustion of biomass for power production can result in PM emissions more than 20 percent higher than emissions from an uncontrolled coal plant. Emissions of carbon monoxide and VOCs can be more than 400 percent and 2,000 percent higher than emissions from a coal plant, respectively. In contrast, NOx emissions may be nearly 60 percent lower and SO2 emissions are virtually eliminated. Combustion of wood wastes, such as construction and demolition debris, may also produce toxic air pollutants.
 One commenter (9198) stated that they are concerned that the rule may have negative, unintended consequences for renewable energy and materials management efforts, as well as their ability to market renewable alternative fuels to customers. The commenter was particularly troubled that the proposed treatment of biogenic CO2 emissions may set a precedent for CO2 emissions accounting in other Agency actions, such as the Section 111 rules for modified and existing power plants, as well as for permitting under the GHG Tailoring Rule. EPA proposes to apply the same accounting method for biogenic CO2 emissions as is used for fossil fuel-derived CO2 emissions from new power plants for purposes of compliance with the NSPS. Although the Agency states that it is evaluating accounting for biogenic emissions from stationary sources, it does not indicate when it will complete its evaluation or how it will develop a biogenic accounting framework. Further, EPA does not explain how such a framework will be reflected in the GHG NSPS for new power plants, or other Agency actions.
The commenter (9198) stated that EPA's treatment of biogenic emissions has implications for new and existing power plants, and other stationary sources, as well as for federal and state renewable energy and fuels programs. The success of these regulatory programs will depend on EPA developing an accounting and compliance framework that can differentiate biogenic emissions from various biomass feedstocks (i.e., by using lifecycle analysis or another approach). The commenter states that the Science Advisory Board (SAB) view that "EPA should not assume carbon neutrality for all biomass energy absent a consideration of a particular feedstock's production and consumption cycle" and that the panel recommended that "not all sources of biogenic CO2 emissions should be treated in the same manner." EPA has yet to initiate the promised rulemaking to address biogenic CO2 emissions. EPA's 111(b) proposal indicates that the Agency intends to treat biogenic- and fossil fuel-derived CO2 as equivalent in affecting the environment. The SAB conclusions do not support such an approach, and the commenter urges EPA to follow the SAB advice and promptly initiate a rulemaking to implement a workable and sound framework for accounting for the categories of emissions identified by the SAB as having a BAF of zero. If the Agency continues on its present course, it will significantly harm the ongoing development of the biogas industry, which are delivering significant GHG reductions, as recognized in EPA's most recent U.S. Inventory of Greenhouse Gas Emissions and Sinks, which documents that U.S. methane emissions fell by 30 percent between 1990 and 2012. The Administration, Congress and the international community recognizes that the use of LFG produced by the decomposition of organic waste materials is a cost-effective and environmentally beneficial way to reduce emissions of methane, a potent greenhouse gas.
One commenter (9409) stated that EPA has committed to using the results of this scientific review process to develop new, permanent regulations that will address the applicability of PSD and Title V to biogenic CO2 emissions from stationary sources. However, EPA has offered no firm timeline for completing a policy or rulemaking process for biogenic CO2 emissions.
 Two commenters (9675; 10029) stated that they along with the rest of the algae industry, urge the EPA to clarify that CO2 beneficial reuse technologies using algae may be applied by affected EGU's, alone or in combination with other technologies, to meet the proposed CO2 emission limits. The commenter supports the comments developed by Sapphire Energy. The commenters provide an extensive description of the benefits and opportunities of applying reuse technology using algae as a means of reducing and sequestering CO2:
      - Algae efficiently converts CO2 and sunlight into green crude oil that, once refined, is fully compatible with the existing transportation infrastructure. Importantly, in its growth process, algae consume enormous amounts of CO2.
      - While palm oil can yield 554 gallons of oil per acre, algae can yield 5,107 gallons per acre- tenfold more.  Further, the production of algae-based fuel does not require arable land or potable water and therefore does not create significant indirect land use effects.
      -There has been a sharp acceleration in the pace of algae-based fuel science and technology, which shows that the commercial-scale production of algae-based fuel is much more practical and is likely to occur much sooner than previously thought.
      - Construction began of the world's first commercial algae-based fuel facility, the Integrated Algal Biorefinery ("IABR") in Columbus, New Mexico.
 One commenter (10681) stated that if EPA wants to exempt primarily biomass fueled facilities from applicability of these requirements, the fossil fuel fraction should be increased from 10% to someplace between 25 and 33% of the total heat input to the utility boiler or cogeneration boiler. They gave the example of a cogeneration facility at a pulp and paper mill that uses coal for 15 to 20% (up to 33%) of its heat input is not primarily fired by biomass. Because this cogeneration unit sells all of its electrical output (more than 219,000 MWh/year and more than 1/3 of its equivalent thermal output), it would be subject to the proposed rule, if it were proposed as a new source. We do not believe that this is the outcome that EPA was intending.
One commenter (9409) stated that they are concerned that EPA mistakenly has proposed to treat biogenic CO2 emissions from fossil fuel-fired EGUs that co-fire biomass in the same manner as fossil fuel emissions. This will discourage the expansion of biomass co-firing and the carbon benefits that it can provide. We urge EPA to reconcile its position on co-fired facilities with its position on biomass generally and to defer regulation of these emissions until the Agency develops a final policy to account for biogenic CO2 emissions. Given the aggressive standards that EPA has proposed for both coal- and natural gas-fired EGUs, facilities may be unwilling to co-fire biomass out of concern that doing so will jeopardize their ability to comply with the proposed emissions limits. Thus, given EPA's recognition of the climate benefits of biomass energy, the proposed rule's treatment of co-fired biomass would likely have the perverse effect of increasing rather than decreasing atmospheric GHG concentrations.
One commenter (9733) states the combustion of biomass does not contribute to the "air pollution" that EPA intends to address through regulation of GHGs. Commenter concludes that biogenic CO2 emissions would not add to atmospheric carbon levels unlike fossil fuel emissions and, therefore, should be excluded from this rule. Commenter continues it would be arbitrary and capricious to regulate biogenic CO2 emissions from CHP units that burn forest products manufacturing residuals for energy recovery because there is no scientific basis to do so. Commenter explains that burning forest products manufacturing residuals releases CO2 (and minor amounts of methane and nitrous oxide) into the atmosphere from the oxidation of the biomass. Burning avoids GHG emissions that would occur anyway if these residuals were not burned because biodegradation can release more methane than combustion, and methane is considered to have a greater impact on global warming than CO2.
Applicability and emissions from non-fossil sources are discussed in Section III.D of the preamble.
Commenter 10131 stated that the EGU GHG states that the SAB report (regarding biogenic emissions) is currently under review and that EPA will, "move forward as warranted once the review is complete." Commenter further stated that by enacting this rule, the EPA is moving forward in opposition to the recommendations made in 2012. Commenter further stated that Low carbon fuels are available for use now. Commenter further stated that their use is tried and true and do not require new technology or research to put into operation. Commenter further stated that in the EPA's efforts to reduce carbon emissions, it is important to use the resources at our disposal and to properly account for operations that lower GHG emissions. Commenter further stated that the EPA should act now on the EGU GHG to incorporate the SAB's recommendations.
Additionally, commenter 10131 stated that the EPA's Landfill Methane Outreach Program (LMOP) encourages the use of LFG as an energy resource. Commenter further stated that one of the primary reasons EPA launched LMOP was to reduce GHGs. Commenter further stated that according to EPA's LMOP website, "CO2 emissions from MSW landfills are not considered to contribute to global climate change because the carbon was contained in recently living biomass. Commenter further stated that the same CO2 would be emitted as a result of the natural decomposition of the organic waste materials outside the landfill environment." Commenter further stated that the EPA change this proposed rule to be consistent with the SAB report and assign a BAF of zero for landfill gas.
 EPA developed the revised draft report, Framework for Assessing Biogenic CO2 Emissions from Stationary Sources, to continue advancing our understanding of the role the use of biomass can play in strategies to address greenhouse gas emissions. Specifically, the Framework was developed as a policy-neutral framework for assessing biogenic CO2 emissions from stationary sources -- it was not developed as technical guidance in conjunction with any specific policy or program. The EPA is engaging in a second round of targeted peer review of the revised draft Framework with the SAB in 2015. Applicability and emissions from non-fossil sources are discussed in Section III.D of the preamble.


[Federal Register Volume 78, Number 128 (Wednesday, July 3, 2013)]
[Proposed Rules]
[Pages 40047-40050]
[FR Doc No: 2013-15956]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2013-0555; Directorate Identifier 2010-SW-047-AD]
RIN 2120-AA64

Airworthiness Directives; Eurocopter Deutschland GmbH Helicopters

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice of proposed rulemaking (NPRM).

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SUMMARY: We propose to adopt a new airworthiness directive (AD) for
Eurocopter Deutschland GmbH (ECD) Model EC135 and MBB-BK 117 C-2
helicopters. This proposed AD is prompted by the discovery during a
routine inspection of loose flight control bearings because of
incorrect installation. This proposed AD would require inspecting the
flight-control bearings repetitively, replacing any loose bearing with
an airworthy flight-control bearing, and installing bushings and
washers. The proposed actions are intended to prevent the affected
control lever from shifting, contacting the helicopter structure, and
reducing control of the helicopter.

DATES: We must receive comments on this proposed AD by September 3,
2013.

ADDRESSES: You may send comments by any of the following methods:
     Federal eRulemaking Docket: Go to http://www.regulations.gov. Follow the online instructions for sending your
comments electronically.
     Fax:<PHONE_NUMBER>.
     Mail: Send comments to the U.S. Department of
Transportation, Docket Operations, M-30, West Building Ground Floor,
Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590-0001.
     Hand Delivery: Deliver to the ``Mail'' address between 9
a.m. and 5 p.m., Monday through Friday, except Federal holidays.

Examining the AD Docket

    You may examine the AD docket on the Internet at http://www.regulations.gov or in person at the Docket Operations Office
between 9 a.m. and 5 p.m., Monday through Friday, except Federal
holidays. The AD docket contains this proposed AD, the economic
evaluation, any comments received, and other information. The street
address for the Docket Operations Office (telephone<PHONE_NUMBER>) is in
the ADDRESSES section. Comments will be available in the AD docket
shortly after receipt.
    For service information identified in this proposed AD, contact
American Eurocopter Corporation, 2701 N. Forum Drive, Grand Prairie, TX
75052; telephone<PHONE_NUMBER> or<PHONE_NUMBER>; fax<PHONE_NUMBER>;
or at http://www.eurocopter.com/techpub. You may review the referenced
service information at the FAA, Office of the Regional Counsel,
Southwest Region, 2601 Meacham Blvd., Room 663, Fort Worth, TX 76137.

FOR FURTHER INFORMATION CONTACT: Matt Fuller, Senior Aviation Safety
Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601
Meacham Blvd., Fort Worth, TX 76137; telephone<PHONE_NUMBER>; email
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Comments Invited

    We invite you to participate in this rulemaking by submitting
written comments, data, or views. We also invite comments relating to
the economic, environmental, energy, or federalism impacts that might
result from adopting the proposals in this document. The most helpful
comments reference a specific portion of the proposal, explain the
reason for any recommended change, and include supporting data. To
ensure the docket does not contain duplicate comments, commenters
should send only one copy of written comments, or if comments are filed
electronically, commenters should submit only one time.
    We will file in the docket all comments that we receive, as well as
a report summarizing each substantive public contact with FAA personnel
concerning this proposed rulemaking. Before acting on this proposal, we
will consider all comments we receive on or before the closing date for
comments. We will consider comments filed after the comment period has
closed if it is possible to do so without incurring expense or delay.
We may change this proposal in light of the comments we receive.

Discussion

    The European Aviation Safety Agency (EASA), which is the Technical
Agent for the Member States of the European Union, has issued AD No.
2010-0058, dated March 30, 2010, (AD 2010-0058), to correct an unsafe
condition for the ECD Model MBB-BK 117 C-2, EC 135 and EC 635
helicopters. EASA advises that during an inspection of an MBB-BK 117 C-
2, ``bearings were detected which had not been correctly fixed.'' As
some bearings on the EC 135 and MBB-BK 117 C-2 type designs are
installed with the same procedure, they are equally affected by the
possibility of the unsafe condition. EASA states that this condition,
if not corrected, could result in the affected control lever shifting
in the axial direction, contacting the helicopter structure, and
subsequently reducing control of the helicopter.

FAA's Determination

    These helicopters have been approved by the aviation authority of
the Federal Republic of Germany and are approved for operation in the
United States. Pursuant to our bilateral agreement with Germany, EASA,
its technical representative, has notified us of the unsafe condition
described in its AD. We are proposing this AD because we evaluated all
known relevant information and determined that an unsafe condition
exists and is likely to exist or develop on other products of these
same type designs.

Related Service Information

    Eurocopter has issued Alert Service Bulletin (ASB) MBB BK117 C-2-
67A-010, Revision 3, dated February 8, 2010, and ASB EC135-67A-019,
Revision 3, dated December 16, 2009. These ASBs specify:
     Within the next 50 flight hours (FHs), inspecting the
affected bearings and, if necessary, rebonding any affected bearings or
replacing the lever assembly.
     Within 12 months, retrofitting bushings on the levers to
prevent movement of the bearings.
     After the retrofit, repeating the inspection every 800 FHs
or 36 months for the Model EC 135 helicopters, whichever comes first,
and 600 FHs or 24 months, whichever comes first, for the Model MBB-BK
117 C-2 helicopters.
    EASA classified these ASBs as mandatory and issued AD 2010-0058 to
ensure the continued airworthiness of these helicopters.

Proposed AD Requirements

    For EC135 helicopters, this proposed AD would require, within 100
hours time-in-service (TIS) or at the next annual inspection, whichever
occurs first, modifying the left-hand (LH) and right-hand (RH) guidance
units and the cyclic shaft by installing bushings and washers to
prevent shifting in the axial direction. This proposed AD would require
at intervals not to exceed 800 hours TIS or 36 months, whichever occurs
first, inspecting the bearings in the LH guidance unit, the RH guidance
unit, cyclic control, upper guidance unit, and linear voltage
differential transducer plate for play. If any bearing is loose, the
proposed AD would require replacing the affected bearing with an
airworthy bearing.
    For MBB-BK 117 C-2 helicopters, this proposed AD would require,
within 100 hours TIS or at the next annual inspection, whichever occurs
first, modifying the LH and RH guidance units and the lateral control
lever by installing bushings and washers to prevent shifting of the
bearings in the axial direction. This proposed AD also would require at
intervals not to exceed 600 hours TIS or 24 months, whichever occurs
first, inspecting the bearings in the RH guidance unit, LH guidance
unit, and lateral control guidance unit for play. If any bearing is
loose, the proposed AD would require replacing the affected bearing
with an airworthy bearing.

Differences between this Proposed AD and the EASA AD

    Differences between this proposed AD and the EASA AD are:
     The EASA AD is applicable to the EC 635 helicopter,
whereas this proposed AD is not because the EC 635 helicopter is not
type certificated in the U.S.
     The EASA AD requires an initial inspection within 50
flight hours or one month, whichever occurs first after May 31, 2008,
and a modification within the next 12 months. This proposed AD would
require the modification within 100 hours TIS or at the next annual
inspection, whichever occurs first, and no inspection until after the
modification has been accomplished.
     The EASA AD provides requirements for certain spare parts,
whereas this proposed AD does not.

Costs of Compliance

    We estimate that this proposed AD would affect 175 Model EC135 and
112 Model MBB-BK 117 C-2 helicopters of U.S. Registry and that labor
costs average $85 per work-hour. Based on these estimates, we would
expect the following costs:
     For EC135 helicopters, it would take about 32 work-hours
to perform the modification. Parts would cost about $312. The total
cost for the modification would be about $3,032 per helicopter and
$530,600 for the U.S. operator fleet. The repetitive inspections would
require 6.5 work-hours for a cost of about $553 per helicopter and
about $96,775 for the fleet per inspection cycle.
     For MBB-BK 117 C-2 helicopters, it would take about 32
work-hours to perform the modification. Parts would cost about $396.
The total cost for the modification would be $3,116 per helicopter and
$348,992 for the U.S. operator fleet. The cost for the repetitive
inspections thereafter would be about $85 per helicopter and $9,520 for
the fleet per inspection cycle.

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, section 106, describes the
authority of the FAA Administrator. ``Subtitle VII: Aviation
Programs,'' describes in more

detail the scope of the Agency's authority.
    We are issuing this rulemaking under the authority described in
``Subtitle VII, Part A, Subpart III, Section 44701: General
requirements.'' Under that section, Congress charges the FAA with
promoting safe flight of civil aircraft in air commerce by prescribing
regulations for practices, methods, and procedures the Administrator
finds necessary for safety in air commerce. This regulation is within
the scope of that authority because it addresses an unsafe condition
that is likely to exist or develop on products identified in this
rulemaking action.

Regulatory Findings

    We determined that this proposed AD would not have federalism
implications under Executive Order 13132. This proposed AD would not
have a substantial direct effect on the States, on the relationship
between the national Government and the States, or on the distribution
of power and responsibilities among the various levels of government.
    For the reasons discussed, I certify this proposed regulation:
    1. Is not a ``significant regulatory action'' under Executive Order
12866;
    2. Is not a ``significant rule'' under the DOT Regulatory Policies
and Procedures (44 FR 11034, February 26, 1979);
    3. Will not affect intrastate aviation in Alaska to the extent that
it justifies making a regulatory distinction; and
    4. Will not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.
    We prepared an economic evaluation of the estimated costs to comply
with this proposed AD and placed it in the AD docket.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
Reference, Safety.

The Proposed Amendment

    Accordingly, under the authority delegated to me by the
Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

    Authority:  49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13  [Amended]

0
2. The FAA amends Sec.  39.13 by adding the following new airworthiness
directive (AD):

Eurocopter Deutschland GmbH: Docket No. FAA-2013-0555; Directorate
Identifier 2010-SW-047-AD.

(a) Applicability

    This AD applies to the following helicopters, certificated in
any category:
    (1) Eurocopter Deutschland GmbH (ECD) Model EC135 P1, P2, P2+,
T1, T2, and T2+ helicopters, serial number (S/N) 0005 through 00829,
with a tail rotor control lever, part number (P/N) L672M2802205 or
L672M1012212; cyclic control lever, P/N L671M1005250; collective
control lever assembly, P/N L671M2020108; or collective control
plate, P/N L671M5040207; installed; and
    (2) Model MBB-BK 117 C-2 helicopters, S/N 9004 through 9310,
with a tail rotor control lever assembly, P/N B672M1007101 or
B672M1807101; tail rotor control lever, P/N B672M1002202 or
L672M2802205; or lateral control lever assembly, P/N B670M1008101,
installed.

(b) Unsafe Condition

    This AD defines the unsafe condition as incorrectly installed
flight control bearings. This condition could cause the affected
control lever to shift and contact the helicopter structure,
resulting in reduced control of the helicopter.

(c) Comments Due Date

    We must receive comments by September 3, 2013.

(d) Compliance

    You are responsible for performing each action required by this
AD within the specified compliance time.

(e) Required Actions

    (1) For Model EC135 P1, P2, P2+, T1, T2, and T2+ helicopters:
    (i) Within the next 100 hours time-in-service (TIS) or at the
next annual inspection, whichever occurs, modify the left-hand (LH)
and right-hand (RH) guidance units and the cyclic shaft by
installing bushings and washers to prevent shifting of the bearings
in the axial direction as follows:
    (A) Remove and disassemble the LH guidance unit and install a
bushing, P/N L672M1012260, between the bearing block and the lever
of the LH guidance unit as depicted in Detail A of Figure 5 of
Eurocopter Alert Service Bulletin EC135-67A-019, Revision 3, dated
December 16, 2009 (EC135 ASB).
    (B) For helicopters without a yaw brake, remove and disassemble
the RH guidance unit and install a bushing, P/N L672M1012260,
between the bearing block and the lever as depicted in Detail B of
Figure 5 of EC135 ASB.
    (C) Remove and disassemble the cyclic shaft and install a
washer, P/N L671M1005260, between the bearing block and the lever as
depicted in Detail C of Figure 6 of EC135 ASB.
    (D) Remove the collective control rod from the bellcrank and
install a washer, P/N L221M1042208, on each side of the collective
control rod and bellcrank as depicted in Detail D of Figure 6 of
EC135 ASB.
    (E) At intervals not to exceed 800 hours TIS or 36 months,
whichever occurs first, inspect the bearings in the LH guidance
unit, RH guidance unit, cyclic control, upper guidance unit, and
linear voltage differential transducer plate for play. If any
bearing is loose, replace the affected bearing with an airworthy
bearing.
    (2) For Model MBB-BK 117 C-2 helicopters:
    (i) Within the next 100 hours TIS or at the next annual
inspection, whichever occurs first, modify the LH and RH guidance
units and the lateral control lever by installing bushings and
washers to prevent shifting of the bearings in the axial direction
as follows:
    (A) Remove and disassemble the RH guidance unit and install a
bushing, P/N L672M1012260, between the lever and the bracket as
depicted in Detail B of Figure 4 of Eurocopter Alert Service
Bulletin MBB BK117 C-2-67A-010, Revision 3, dated February 8, 2010
(BK117 ASB). Remove and disassemble the LH guidance unit and install
a bushing, P/N L672M1012260, between the lever and the bracket as
depicted in Detail C of Figure 4 of BK117 ASB.
    (B) Remove the lateral control lever and install new bushings in
accordance with the Accomplishment Instructions, paragraphs
3.C(9)(a) through 3.C(9)(g), of BK 117 ASB.
    (C) Identify the modified lever assembly by writing ``MBB BK117
C-2-67A-010'' on the lever with permanent marking pen and protect
with a single layer of lacquer (CM 421 or equivalent).
    (D) Apply corrosion preventive paste (CM 518 or equivalent) on
the shank of the screws and install airworthy parts as depicted in
Figure 5 of BK117 ASB.
    (E) At intervals not to exceed 600 hours TIS or 24 months,
whichever occurs first, inspect the bearings in the RH guidance
unit, LH guidance unit, and lateral control guidance unit for play.
If any bearing is loose, replace the affected bearing with an
airworthy bearing.

(f) Alternative Methods of Compliance (AMOC)

    (1) The Manager, Safety Management Group, FAA, may approve AMOCs
for this AD. Send your proposal to: Matt Fuller, Senior Aviation
Safety Engineer, Safety Management Group, Rotorcraft Directorate,
FAA, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone (817) 222-
5110; email<EMAIL_ADDRESS>    (2) For operations conducted under a 14 CFR part 119 operating
certificate or under 14 CFR part 91, subpart K, we suggest that you
notify your principal inspector, or lacking a principal inspector,
the manager of the local flight standards district office or
certificate holding district office before operating any aircraft
complying with this AD through an AMOC.

(g) Additional Information

    The subject of this AD is addressed in European Aviation Safety
Agency (EASA) AD

No. 2010-0058, dated March 30, 2010. You may view the EASA AD at
http://www.regulations.gov in Docket No. FAA-2013-0555.

 (h) Subject

    Joint Aircraft Service Component (JASC) Code: 6710, Main Rotor
Control.

    Issued in Fort Worth, Texas, on June 18, 2013.
Kim Smith,
Directorate Manager, Rotorcraft Directorate, Aircraft Certification
Service.
[FR Doc. 2013-15956 Filed 7-2-13; 8:45 am]
BILLING CODE 4910-13-P


[Federal Register: July 24, 2008 (Volume 73, Number 143)]
[Notices]
[Page 43222-43224]
[DOCID:fr24jy08-60]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[ Docket Nos. ER91-195-051; EL07-69-001]

 Western Systems Power Pool; Western Systems Power Pool
Agreement; Order Addressing Request for Reconsideration and Providing
An Opportunity for Further Comments

Issued July 17, 2008.
    Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G.
Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.
    1. On February 21, 2008, the Commission issued an order on the
Western System Power Pool (WSPP) Agreement rates, finding that it is
not just and reasonable to allow a seller to use the WSPP-wide ``up
to'' demand charge as a ceiling rate in markets where the seller does
not have market-based rate authority, unless such a seller can cost-
justify the use of the ``up to'' demand charge based on its own fixed

costs.\1\ On March 24, 2008, Arizona Public Service Company (APS) and
Xcel Energy Services Inc. (Xcel) filed a joint request for
reconsideration of the WSPP Agreement Order, requesting that the
Commission adopt an alternative implementation of the WSPP Agreement
Order by incorporating company-specific demand charge caps into the
WSPP Agreement, either by cross-reference to a specific cost-based
tariff, or by incorporation of company-specific rate schedules into the
WSPP Agreement itself.\2\ In this order, we address the request for
reconsideration. We deny APS's and Xcel's request with respect to the
cross-reference proposal, and provide an opportunity for WSPP and other
interested parties to comment on the proposal for incorporating
company-specific rate schedules, as discussed below.
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    \1\ Western Sys. Power Pool, 122 FERC ] 61,139 (2008) (February
21 Order).
    \2\ APS and Xcel describe this proposal as incorporating into
the WSPP Agreement company-specific schedules of demand charge cost
caps. Under APS and Xcel's second proposal, they would continue to
use the non-rate terms and conditions of service under the WSPP
Agreement.
---------------------------------------------------------------------------

I. Background

    2. The WSPP Agreement was initially accepted by the Commission on a
non-experimental basis in 1991,\3\ and provided for flexible pricing
for coordination sales and transmission services. In accepting the WSPP
Agreement, the Commission rejected WSPP's proposed system of price caps
based on the costs of its highest cost participants, and instead
developed energy and transmission rate ceilings based on the costs of a
subset (18 sellers) of the original parties to the WSPP Agreement.\4\
The U.S. Court of Appeals for the District of Columbia Circuit upheld
the Commission's acceptance of the WSPP Agreement.
---------------------------------------------------------------------------

    \3\ Western Sys. Power Pool, 55 FERC ] 61,099, order on reh'g,
55 FERC ] 61,495 (1992) (Initial Order), aff'd in relevant part and
remanded in part sub nom. Environmental Action and Consumer
Federation of America v. FERC, 996 F.2d 401 (DC Cir. 1992), order on
remand, 66 FERC ] 61,201 (1994) (Environmental Action). Prior to
1991, the WSPP Agreement was used for three years on an experimental
basis. See Western Sys. Power Pool, 50 FERC ] 61,339 (1990)
(extending the initial two-year period for an additional year).
    \4\ See Initial Order, 55 FERC ] 61,099 at 61,321-25.
---------------------------------------------------------------------------

    3. On June 21, 2007, the Commission instituted a section 206
proceeding to investigate whether the WSPP Agreement ceiling rate
continued to be just and reasonable for a public utility seller in
markets in which such seller was found to have or was presumed to have
market power.\5\ The Commission limited the investigation to: (1) the
justness and reasonableness of WSPP Agreement cost-based ceiling rates
for coordination energy sales by public utility sellers that are found
to have, or are presumed to have, market power; and (2) if the existing
WSPP Agreement rates are unjust and unreasonable for such sellers, how
the Commission should establish a just and reasonable rate. The
Commission sought comment on whether the Commission should set a just
and reasonable ``up to'' rate based on: (1) Individual sellers'' costs;
(2) a new agreement-wide ``up to'' rate based on the costs of a
representative group of WSPP sellers (including how such agreement-wide
rate should be calculated); or (3) or a different methodology.
---------------------------------------------------------------------------

    \5\ Western Sys. Power Pool, 119 FERC ] 61,302 at P 9 (2007)
(Order Instituting Hearing).
---------------------------------------------------------------------------

    4. In the February 21 Order, the Commission found that it is not
just and reasonable to allow such a seller to continue to use the WSPP-
wide ``up to'' demand charge as a ceiling rate unless such a seller can
cost-justify the use of the ``up to'' demand charge based on its own
fixed costs. Accordingly, the Commission directed all sellers under the
WSPP Agreement that lack market-based rate authorization, or that have
lost or relinquished their market-based rate authority (including those
sellers currently using the WSPP Agreement as mitigation), who wish to
continue transacting under the WSPP Agreement, to make a filing within
60 days of the date of issuance of that order providing cost
justification \6\ to demonstrate that use of the WSPP Agreement ``up
to'' demand charge is just and reasonable for that particular seller.
The Commission stated that, if a seller provides cost support
demonstrating that the ``up to'' demand charge under the WSPP Agreement
does not exceed the demand charge that the seller can cost-justify
based on its own fixed costs, the seller may continue to use the WSPP
Agreement.
---------------------------------------------------------------------------

    \6\ The Commission stated that such changes should be filed
pursuant to section 35.13 of the Commission's regulations. 18 CFR
35.13 (2008).
---------------------------------------------------------------------------

    Otherwise, such seller must file a separate stand-alone rate
schedule, to be effective as of the date of the compliance filing that
is cost-justified based on the individual seller's own costs. In the
latter case, such seller could propose to use the non-rate terms and
conditions of the WSPP Agreement, but would have to include those
provisions as part of its stand-alone rate schedule.

II. Request for Reconsideration

    5. APS and Xcel state that they are not seeking to reverse the
Commission's ruling in the February 21 Order that sellers may not
automatically rely upon the capped rates in the WSPP Agreement in
markets where they do not have market-based rate authority. Rather, APS
and Xcel request that the Commission reconsider how this ruling is to
be implemented, so as to preserve the numerous benefits of transacting
under the WSPP Agreement for those mitigated sellers that might require
company-specific cost caps, and for their counterparties.
    6. APS and Xcel argue that the February 21 Order eliminates the
efficiencies inherent in the WSPP Agreement for certain WSPP members,
because a seller that is unable to provide cost justification for the
``up-to'' demand charge included in the WSPP Agreement would be
precluded from selling under the WSPP Agreement. APS and Xcel contend
that, even though a seller could seek to mimic the benefits of the WSPP
Agreement by filing a separate agreement that contains the same terms
and conditions, the seller would still need to enter into bilateral
agreements with each WSPP member with which it would want to transact.
APS and Xcel argue that each of the counterparties would then need to
familiarize itself with the terms and conditions of the seller's stand-
alone rate schedule and confirm that the terms and conditions included
in the stand-alone rate schedule mirror those contained in the WSPP
Agreement. APS and Xcel further state that other process adjustments
would be required, such as making advance bilateral arrangements prior
to transactions taking place under a stand-alone rate schedule. They
also contend that additional credit obligations would necessarily be
required by stand-alone rate schedules, as well as possible additional
collateral postings. APS and Xcel maintain that such additional steps
could take more time than a potential buyer is willing to spend, which
they argue could limit the number of potential trading partners.
    7. APS and Xcel also argue that the Commission's remedy in the
February 21 Order results in inefficient use of company and Commission
resources and may result in inconsistent conditions of sales for power
and energy. They contend that, in the event revisions are made to the
terms and conditions of the WSPP Agreement, each WSPP member that
utilizes those terms under a stand-alone rate schedule will be required
to propose and file similar conforming revisions to keep the terms and
conditions consistent. APS and Xcel further maintain that the
Commission could be required to process and evaluate numerous rate

schedule changes. Additionally, they argue that there may be a lag
between the effective date of the revisions to the WSPP Agreement and
the effective date of revisions in a company's stand-alone rate
schedule, which they claim will create confusion between
counterparties. APS and Xcel contend that confusion may also result in
transactions between parties if a WSPP member does not incorporate each
and every revision to the WSPP Agreement in the company-specific stand-
alone rate schedule. They explain that a prospective buyer may have the
mistaken impression that the seller has implemented every term and
condition of the WSPP Agreement in the stand-alone rate schedule, when,
in fact, a seller has not proposed certain revisions.
    8. APS and Xcel suggest what they describe as less procedurally
complex, alternative approaches to implement the February 21 Order,
including allowing cross-referencing of company-specific cost-based
demand charges in a separate cost-based tariff. Alternatively, they
suggest that the Commission could permit company-specific rate
schedules to be incorporated into the WSPP Agreement itself.

III. Commission Determination

    9. In the Order Instituting Hearing, the Commission emphasized that
it was not investigating whether sellers that are found to have market
power, or are presumed to have market power, may continue to use the
non-rate terms and conditions under the WSPP Agreement; nor was the
Commission investigating the transmission rates under the WSPP
Agreement. Moreover, in the February 21 Order, the Commission
emphasized that the finding reached would affect only a limited number
of sellers. The Commission specifically stated that it was not
requiring each WSPP member public utility to cost-justify the use of
the WSPP Agreement demand charge or to file an individual cost-based
rate. Instead, the Commission required only those jurisdictional
sellers that lack market-based rate authorization, or those sellers
that lose or relinquish their market-based rate authority (including
those sellers currently using the WSPP Agreement as mitigation), to
provide cost justification to demonstrate that use of the WSPP ``up
to'' demand charge is just and reasonable for those particular sellers.
Only if such sellers cannot justify the demand charge would they need
to file a separate, stand-alone rate schedule that could mirror the
non-rate terms and conditions of the WSPP Agreement. Thus, only a
limited number of utilities are affected by the February 21 Order.\7\
---------------------------------------------------------------------------

    \7\ We note that two sellers have filed cost justification for
continued use of the WSPP Agreement demand charge. Those filings are
pending before the Commission. Three others, including APS, filed
letters stating that they would not use the WSPP Agreement in
balancing authority areas in which they are mitigated.
---------------------------------------------------------------------------

    10. The proposal by APS and Xcel to cross-reference company-
specific cost-based demand charges in the WSPP Agreement is not
consistent with Commission requirements. The Commission requires public
utilities to post full and complete rate schedules and tariffs, rather
than incorporating rates by reference.\8\ Accordingly, we will deny
APS' and Xcel's request for reconsideration on this proposal.
---------------------------------------------------------------------------

    \8\ See 18 CFR 35.1(a) (2008); see also Louisville Gas and
Electric Co., 114 FERC ] 61,282, at P 186 (2006).
---------------------------------------------------------------------------

    11. APS and Xcel alternatively propose that the Commission permit
company-specific rates in rate schedules to be incorporated into the
WSPP Agreement. They argue that the requirement in the February 21
Order that sellers who cannot justify the demand charge must file a
separate, stand-alone rate schedule will reduce efficiencies for
certain WSPP members and cause potential waste of Commission resources.
APS and Xcel cite the need for additional credit checks and postings,
as well as potential numerous rate schedule changes, as examples of
requirements that will discourage potential trading partners from
entering into agreements with WSPP members.
    12. The proposal to allow the incorporation of company-specific
rates in rate schedules in the WSPP Agreement would require amendment
of the WSPP Agreement. To assist us in our analysis of this proposal,
we will provide WSPP and any other interested party the opportunity to
submit comments on the proposal to incorporate company-specific rate
schedules into the WSPP Agreement within 30 days of the date of
issuance of this order, with reply comments due 15 days thereafter.
    The Commission orders:
    (A) APS' and Xcel's request for reconsideration is hereby denied
with respect to the proposal to cross-reference company-specific demand
charges in the WSPP Agreement, as discussed in the body of this order.
    (B) The Commission hereby provides WSPP and interested parties an
opportunity to comment on the proposal to incorporate company-specific
rate schedules in the WSPP Agreement within 30 days of the date of
issuance of this order, and reply comments within 15 days, as discussed
above.
    (C) The Secretary is directed to publish a copy of this order in
the Federal Register.

    By the Commission.
Kimberly D. Bose,
Secretary.
[FR Doc. E8-16914 Filed 7-23-08; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 86, Number 226 (Monday, November 29, 2021)]
[Notices]
[Pages 67757-67758]
[FR Doc No: 2021-25913]

-----------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION

[SEC File No. 270-221, OMB Control No. 3235-0232]

Proposed Collection; Comment Request; Extension: Form 1-E,
Regulation E

Upon Written Request, Copies Available From: Securities and Exchange
Commission, Office of FOIA Services, 100 F Street NE, Washington, DC
20549-2736

Notice is hereby given that, pursuant to the Paperwork Reduction Act of
1995 (44 U.S.C. 3501 et seq.), the Securities and Exchange Commission
(the ``Commission'') is soliciting comments on the collection of
information summarized below. The Commission plans to submit this
existing collection of information of the Office of Management and
Budget for extension and approval.
    Form 1-E (17 CFR 239.200) under the Securities Act of 1933 (15
U.S.C. 77a et seq.) (``Securities Act'') is the form that a small
business investment company (``SBIC'') or business development company
(``BDC'') uses to notify the Commission that it is claiming an
exemption under Regulation E from registering its securities under the

Securities Act. Rule 605 of Regulation E (17 CFR 230.605) under the
Securities Act requires an SBIC or BDC claiming such an exemption to
file an offering circular with the Commission that must also be
provided to persons to whom an offer is made. Form 1-E requires an
issuer to provide the names and addresses of the issuer, its
affiliates, directors, officers, and counsel; a description of events
which would make the exemption unavailable; the jurisdictions in which
the issuer intends to offer the securities; information about
unregistered securities issued or sold by the issuer within one year
before filing the notification on Form 1-E; information as to whether
the issuer is presently offering or contemplating offering any other
securities; and exhibits, including copies of the rule 605 offering
circular and any underwriting contracts.
    The Commission uses the information provided in the notification on
Form 1-E and the offering circular to determine whether an offering
qualifies for the exemption under Regulation E. The Commission
estimates that, each year, one issuer files one notification on Form 1-
E, together with offering circulars, with the Commission.\1\ Based on
the Commission's experience with disclosure documents, we estimate that
the burden from compliance with Form 1-E and the offering circular
requires approximately 100 hours per filing. The annual burden hours
for compliance with Form 1-E and the offering circular would be 200
hours (2 responses x 100 hours per response). Estimates of the burden
hours are made solely for the purposes of the PRA, and are not derived
from a comprehensive or even a representative survey or study of the
costs of SEC rules and forms.
---------------------------------------------------------------------------

    \1\ According to Commission records, one issuer filed two
notifications on Form 1-E, together with offering circulars, during
2013 and 2014.
---------------------------------------------------------------------------

    Written comments are invited on: (a) Whether the proposed
collection of information is necessary for the proper performance of
the functions of the agency, including whether the information will
have practical utility; (b) the accuracy of the agency's estimate of
the burden of the collection of information; (c) ways to enhance the
quality, utility, and clarity of the information collected; and (d)
ways to minimize the burden of the collection of information on
respondents, including through the use of automated collection
techniques or other forms of information technology. Consideration will
be given to comments and suggestions submitted in writing within 60
days of this publication.
    Please direct your written comments to David Bottom, Director/Chief
Information Officer, Securities and Exchange Commission, c/o John R.
Pezzullo, 100 F Street NE, Washington, DC 20549; or send an email to:
[email protected].

    Dated: November 23, 2021.
J. Matthew DeLesDernier,
Assistant Secretary.
[FR Doc. 2021-25913 Filed 11-26-21; 8:45 am]
BILLING CODE 8011-01-P


[Federal Register: May 8, 2008 (Volume 73, Number 90)]
[Rules and Regulations]
[Page 25961-25962]
[DOCID:fr08my08-1]

========================================================================
Rules and Regulations
                                                Federal Register
________________________________________________________________________

This section of the FEDERAL REGISTER contains regulatory documents
having general applicability and legal effect, most of which are keyed
to and codified in the Code of Federal Regulations, which is published
under 50 titles pursuant to 44 U.S.C. 1510.

The Code of Federal Regulations is sold by the Superintendent of Documents.
Prices of new books are listed in the first FEDERAL REGISTER issue of each
week.

========================================================================

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2007-0284; Directorate Identifier 2004-SW-06-AD;
Amendment 39-15510; AD 2008-10-04]
RIN 2120-AA64

Airworthiness Directives; Sikorsky Aircraft Corporation Model S-
61A, S-61D, S-61E, and S-61V Helicopters

AGENCY: Federal Aviation Administration, DOT.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: This amendment adopts a new airworthiness directive (AD) for
the specified Sikorsky Aircraft Corporation (Sikorsky) model
helicopters that requires installing an electric chip detector on each
engine and an on-board chip detector annunciation system. The AD also
requires revising the Rotorcraft Flight Manual (RFM) to add procedures
for crew response to the illumination of an on-board chip detector
warning light. This AD also requires testing the engine chip detector
system at specified intervals. This amendment is prompted by reports of
Number 5 engine bearing failures. Failure of the bearing resulted in
erratic movement of the high-speed, engine-to-transmission shaft
(shaft), an oil leak, an in-flight fire, and an emergency landing. The
actions specified by this AD are intended to detect an impending
bearing failure, which if undetected and not addressed by appropriate
crew action may result in an oil leak, a severed shaft housing, an
uncontained in-flight fire, and a subsequent emergency landing.

DATES: Effective June 12, 2008.
    The incorporation by reference of certain publications listed in
the regulations is approved by the Director of the Federal Register as
of June 12, 2008.

ADDRESSES: You may get the service information identified in this AD
from Sikorsky Aircraft Corporation, Attn: Manager, Commercial Technical
Support, mailstop s581a, 6900 Main Street, Stratford, Connecticut,
phone<PHONE_NUMBER>, e-mail address<EMAIL_ADDRESS>    Examining the Docket: You may examine the docket that contains this
AD, any comments, and other information on the Internet at http://
www.regulations.gov or at the Docket Operations office, West Building
Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington,
DC.

FOR FURTHER INFORMATION CONTACT: Kirk Gustafson, Aviation Safety
Engineer, Boston Aircraft Certification Office, Engine and Propeller
Directorate, 12 New England Executive Park, Burlington, MA 01803,
telephone<PHONE_NUMBER>, fax<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION: A proposal to amend 14 CFR part 39 to
include an AD for the specified model helicopters was published in the
Federal Register on December 6, 2007 (72 FR 68766). That action
proposed to require, within 60 days, installing an electric chip
detector for the Number 5 bearing in both engines on the specified
Sikorsky model helicopters with GE CT58 series engines. That action
also proposed installing an on-board chip detector annunciation system
and revising the Emergency Procedures section of the RFM to add
procedures for crew response to the illumination of an on-board chip
detector warning light. In addition, functional testing of the chip
detector system at specified intervals was proposed.
    We have reviewed Sikorsky Alert Service Bulletin No. 61B30-15A,
Revision A, dated October 20, 2003 (ASB). The Sikorsky ASB describes
procedures for installing an engine chip detector system that will
provide an ``in-cockpit monitoring system'' as a means to detect
metallic chips if bearing deterioration occurs in either engine. We
have also reviewed General Electric (GE) Aircraft Engines CT58 Service
Bulletin Number 72-0195, dated May 1, 2003 (SB). The GE SB describes
procedures for installing an alternate electrical chip detector (either
part number (P/N) 3018T72P01, cannon-type connector, or 3049T42P01,
stud-type connector) to the power turbine accessory drive assembly.
    Interested persons have been afforded an opportunity to participate
in the making of this amendment. Due consideration has been given to
the two comments made by one commenter about two typographical errors
in the Notice of proposed rulemaking (NPRM). In paragraph (a) of the
NPRM, an engine chip detector is incorrectly shown as P/N 205T33P01
rather than P/N 2005T33P01. In paragraph (d), we referenced paragraph
3.F. of the Sikorsky ASB rather than 3.E.
    We concur with the commenter and have changed the engine chip
detector P/N from 205T33P01 to 2005T33P01 and have changed the
referenced Sikorsky ASB paragraph from 3.E. to 3.F. in this AD.
    After careful review of the available data, including the comments
noted above, we determined that air safety and the public interest
require the adoption of the rule with the changes described previously.
These changes will neither increase the economic burden on any operator
nor increase the scope of the AD.
    This AD will affect 7 helicopters of U.S. registry, and it will
take about 81.5 work hours per helicopter to install the engine chip
detector and the on-board cockpit annunciation system. The repetitive
tests will affect about 7 helicopters and require 6 tests per year and
1 work hour per test for 10 years of operating service. The average
labor rate is $80 per work hour. Required parts will cost about $1,940
per helicopter. Based on these figures, we estimate the total cost
impact of the AD on U.S. operators to be $92,820 for the entire fleet.

Regulatory Findings

    We have determined that this AD will not have federalism
implications under Executive Order 13132. This AD will not have a
substantial direct effect on the States, on the relationship between
the national Government and the States, or on the distribution of power
and responsibilities among the various levels of government.
    For the reasons discussed above, I certify that the regulation:
    1. Is not a ``significant regulatory action'' under Executive Order
12866;
    2. Is not a ``significant rule'' under the DOT Regulatory Policies
and Procedures (44 FR 11034, February 26, 1979); and

    3. Will not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.
    We prepared an economic evaluation of the estimated costs to comply
with this AD. See the AD docket to examine the economic evaluation.

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, Section 106, describes the
authority of the FAA Administrator. Subtitle VII, Aviation Programs,
describes in more detail the scope of the Agency's authority.
    We are issuing this rulemaking under the authority described in
Subtitle VII, Part A, Subpart III, Section 44701, ``General
requirements.'' Under that section, Congress charges the FAA with
promoting safe flight of civil aircraft in air commerce by prescribing
regulations for practices, methods, and procedures the Administrator
finds necessary for safety in air commerce. This regulation is within
the scope of that authority because it addresses an unsafe condition
that is likely to exist or develop on products identified in this
rulemaking action.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
reference, Safety.

Adoption of the Amendment

0
Accordingly, pursuant to the authority delegated to me by the
Administrator, the Federal Aviation Administration amends part 39 of
the Federal Aviation Regulations (14 CFR part 39) as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

    Authority: 49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13  [Amended]

0
2. Section 39.13 is amended by adding a new airworthiness directive to
read as follows:

2008-10-04 Sikorsky Aircraft Corporation: Amendment 39-15510. Docket
No. FAA-2007-0284; Directorate Identifier 2004-SW-06-AD.

Applicability

    Model S-61A, S-61D, S-61E, and S-61V helicopters with GE CT 58
series engines installed, certificated in any category.

Compliance

    Required within 60 days, unless accomplished previously.
    To detect an impending Number 5 engine bearing (bearing)
failure, which if undetected and not addressed by appropriate crew
action may result in an oil leak, severed shaft housing, an
uncontained in-flight fire, and a subsequent emergency landing, do
the following:
    (a) Remove engine chip detector, part number (P/N) 2005T33P01,
and install engine chip detector, P/N 3049T42P01 or 3018T72P01, in
the engine power turbine accessory drive assembly of each engine.
Install the chip detector by following the Accomplishment
Instructions, paragraph 3.B., of General Electric Aircraft Engines
CT58 Service Bulletin Number 72-0195, dated May 1, 2003.

    Note: This AD neither requires installing GE CT58 engines nor
replacing an engine power turbine accessory drive assembly that has
a 5/16 inch magnetic plug port and applies only to Sikorsky Model S-
61A, S-61D, S-61E, and S-61V helicopters with GE CT58 series engines
installed.

    (b) Install an on-board engine chip detector annunciation system
by following the Accomplishment Instructions, paragraphs 3.B. or
3.C., as appropriate for the different manufacturers of the master
warning caution panel, of the Sikorsky Aircraft Corporation Alert
Service Bulletin No. 61B30-15A, Revision A, dated October 20, 2003
(Sikorsky ASB).
    (c) After doing paragraph (b) of this AD, before further flight,
perform a functional test of the engine chip detector system. Repeat
the test at intervals not to exceed 150 hours time-in-service.
Conduct the tests following the Accomplishment Instructions,
paragraph 3.D., of the Sikorsky ASB.
    (d) Insert the emergency procedures contained in the
Accomplishment Instructions, paragraph 3.F., of the Sikorsky ASB for
an on-board engine chip detector warning indicator light into the
Emergency Procedures section of the applicable Rotorcraft Flight
Manual.
    (e) To request a different method of compliance or a different
compliance time for this AD, follow the procedures in 14 CFR 39.19.
Contact the Manager, Boston Aircraft Certification Office, Engine
and Propeller Directorate, FAA, ATTN: Kirk Gustafson, Aviation
Safety Engineer, 12 New England Executive Park, Burlington, MA
01803, telephone<PHONE_NUMBER>, fax<PHONE_NUMBER>, for information
about previously approved alternative methods of compliance.
    (f) Installing an engine chip detector shall be done by
following the specified portions of General Electric Aircraft
Engines CT58 Service Bulletin Number 72-0195, dated May 1, 2003.
Installing an on-board engine chip detector annunciation system and
performing a functional test of the engine chip detector system
shall be done by following the specified portions of Sikorsky
Aircraft Corporation Alert Service Bulletin No. 61B30-15A, Revision
A, dated October 20, 2003. The Director of the Federal Register
approved this incorporation by reference in accordance with 5 U.S.C.
552(a) and 1 CFR part 51. Copies may be obtained from Sikorsky
Aircraft Corporation, Attn: Manager, Commercial Technical Support,
mailstop s581a, 6900 Main Street, Stratford, Connecticut, phone
(203) 383-4866, e-mail address<EMAIL_ADDRESS>Copies may
be inspected at the FAA, Office of the Regional Counsel, Southwest
Region, 2601 Meacham Blvd., Room 663, Fort Worth, Texas, or at the
National Archives and Records Administration (NARA). For information
on the availability of this material at NARA, call<PHONE_NUMBER>, or
go to: http://www.archives.gov/federal_register/code_of_federal_
regulations/ibr_locations.html.
    (g) This amendment becomes effective on June 12, 2008.

    Issued in Fort Worth, Texas, on April 23, 2008.
David A. Downey,
Manager, Rotorcraft Directorate, Aircraft Certification Service.
[FR Doc. E8-9787 Filed 5-7-08; 8:45 am]

BILLING CODE 4910-13-P