Because both units meet the applicability definition in the proposed Transport Rule, Cogentrix has conducted an analysis of allocations and required reductions from 2005 baseline emissions data using the methodology discussed in the preamble of the proposed rule. The calculation methodology is presented in Attachment I and the results are presented in Table I. Cogentrix requests that allocations for both the Hopewell and Portsmouth sites be added to the Virginia state-wide allocation allotment as detailed in Table 1 below. Cogentrix has used 2005 coal throughput data to develop these allocation estimates as prescribed in the proposed rule background. In addition, current S02 control efficiencies have been incorporated into the allocation estimates as these units were installed after 2005. [EPA-HQ-OAR-2009-0491-2772.1, p.2]
[See EPA-HQ-OAR-2009-0491-2772.1, p.3 for Table 1]
Cogentrix Supports Credit Allocation Delegation to State Agencies. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
EPA proposes a very aggressive timeline for implementation ofthe Transport Rule, with allocations for some states beginning in 2012. Given the number of affected facilities and short timeframe for implementation, Cogentrix supports the maximum possible delegation of the Transport Rule and allocation allotment to state agencies. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
Since the criteria for affected sources differs under many EPA rules, a true dataset for emissions allocation development is unlikely to be available for EPA's use. Cogentrix has already identified two of its sites that were not included in the allocation allotments used for proposed rule development. Cogentrix believes that each state is likely to have hands-on knowledge of affected facilities, implemented controls, and operational status so that allocation allotments can be properly and more readily distributed and reviewed. Furthermore, Cogentrix requests that each state be able to comment on their allocation allotment to ensure that all sources are properly accounted for in the state's total and that proper adjustments can be made prior to rule finalization. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
Response:
Thank you for your comment.Organization: Consumers Energy
Comment:
Consumers Energy
F. The Proposed Allowance Allocations Are Inadequate to Support a Limited Trading Program
1. Group 1 SO2 States
In order to understand whether or not allowances will be available in the market to purchase, Consumers Energy first took a look at historic S02 emission rates and heat input data (2005-2009) for each of the states listed as a Group I state. The maximum heat input over that five year period was multiplied by the minimum SO2 emission rate over that same time period and the resulting emissions were used as a baseline emission for the years 2012 through 2016. The announced Flue Gas Desulfurization (FGD) retrofits as of August 2010 that were reported by CERA were compiled for each state (assuming a 95% reduction in SO2 emissions for each unit retrofitted) and the emissions were then adjusted downward accordingly. The newly adjusted emissions for each state were then compared to their proposed state budgets. As shown in the tables below, there will be little to no excess SO2 allowances available for purchase in any of the 15 Group 1 states. [EPA-HQ-OAR-2009-0491-2837.1, p.11]
[The tables referred to in 1. Group 1 SO2 States can be found on page 11 of this comment.]
2. Annual NOx States
In order to understand whether or not allowances will be available in the market to purchase, Consumers Energy first took a look at historic NOx emission rates and heat input data (2005-2009) for each of the states that have Annual NOx compliance requirements. The maximum heat input over that five year period was multiplied by the minimum NOx emission rate over that same time period and the resulting emissions were used as a baseline emission for the years 2012 through 2016. The announced Selective Catalytic Reduction (SCR)/Selective Non-Catalytic Reduction (SNCR) retrofits as of August 2010 that were reported by CERA were compiled for each state (assuming a 30% reduction in SO2 emissions for each unit retrofitted with an SNCR and a 0.06 lb/mmbtu emission rate for each unit retrofitted with an SCR) and the emissions were then adjusted downward accordingly. The newly adjusted emissions for each state were then compared to each state's proposed budget. As shown in the tables below, there will be little to no excess Annual NOx allowances available for purchase in any of the states that are required to comply with the Annual NOx limits as proposed by the EPA. [EPA-HQ-OAR-2009-0491-2837.1, p.12]
[The tables referred to in 2. Annual NOx States can be found on pages 12-13 of this comment.]
Given the limited amount of time available due to the compressed comment period, and using the most readily available information, preliminary analysis results indicate there will be little to no allowance markets. Under CAIR companies had the option to use banked allowances, both SO2 and NOx, as part of their compliance plan in order to reasonably stagger the scheduled installation of Pollution Control Equipment for a 2017 compliance date. There are many benefits to this approach:
:: Less demand on materials; this means lower procurement costs and lower impact to customers.
:: Less demand on replacement power; this also means lower impact to customers.
:: Staggered installations result in multiple gradual increases to customer rates as opposed to a few rather large rate increases. [EPA-HQ-OAR-2009-0491-2837.1, p.13]
:: If a limited trading program cannot be crafted to satisfy the D.C. Circuit Court's ruling, then state-wide trading or averaging should be the next choice.
:: Allocations should be handled by the states. The states know their jurisdictions and their sources best. A total allowance budget should be assigned to each state. They can handle the distribution schemes. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Response:
As described in Preamble Section VII.A, banking of allowances is allowed under the Transport Rule programs.  EPA's modeling projections of the Transport Rule show that many states, particularly Group 1 states, have the capacity to overcomply with (i.e., emit below) their 2012 budgets and therefore establish an allowance bank that they may access in subsequent years to gain all of the economic and planning advantages cited by the commenter.  EPA's detailed power sector dispatch modeling offers a superior degree of unit-level detail and least-cost electricity supply functions than the calculations provided by the commenter, and based on these modeled projections, EPA disagrees with the commenter that "little to no excess" allowances will be available under the Transport Rule air quality-assured trading programs.  EPA notes that the intent of the Transport Rule's market-based regulation is to incentivize every covered unit to achieve whatever cost-effective reductions are available based on the market signal (e.g., allowance price) created by the imposition of state budgets on the fleet.  In prior market-based emissions trading programs, sources have found cost-effective reduction strategies that were not anticipated by regulators, which have helped to create even larger allowance banks than originally modeled upon promulgation of the related regulations.  EPA believes that the Transport Rule programs as designed will promote liquid allowance markets with an adequate margin for trading and banking at the outset of the program, as its modeling projections show; however, although the Agency could not base the details (e.g., state budgets) of this regulation on this expectation, EPA also finds it reasonable to anticipate that the sector may again outstrip the modeled cost-effective emission reductions and potentially provide additional reductions that the programs incentivize but that regulators do not specifically foresee at this time.  For these reasons, EPA believes the concerns raised by this commenter are unfounded and unsupported by either the information presented for this rulemaking or the wealth of experience the power sector and the Agency have gained from prior emissions trading programs.
Organization: Dairyland Power Cooperative
Comment:
Dairyland Power Cooperative
II. John P. Madgett (Bl): S02 Allocations and Direct Control Alternative S02 Emission Rates Based on Only the Lowest Sulfur Coal Quality Produced in the Powder River Basin is Not a Reasonable Assumption.
In Attachment I, Dairyland Power proposes revisions to the S02 allocations and direct control S02 emission rates for John P. Madgett (BI). Historically, Dairyland Power has procured coal from the Power River Basin (PRE) for John P. Madgett (BI) with a range of coal sulfur quality and corresponding S02 emission rate that is generally representative - - up to approx. 1.1 lb S02 /rnrnBtu - - of the range of sulfur concentration found in coals produced in the PRB. Coal procurement decisions are based on numerous factors, some of which are, compatibility with boiler performance, product availability to a low volume buyer like Dairyland Power, product price, transportation availability, transportation price, along with other typical contractual terms. [EPA-HQ-OAR-2009-0491-2733.1 p.3-4
It is not conceivable that coal production from only a limited portion of the PRB coal fields - only the mine(s) in the PRB having the very lowest sulfur quality coal - - could satisfy the coal demand created by the EPA's assumed 2012 and 2014 S02 direct control emission rate, and corresponding S02 allocations, based on the 'lowest sulfur' coal quality produced in the PRB. Not only is it questionable to assume there is the production capacity to produce the quantities necessary to meet demand for the lowest sulfur quality PRB coal, it is also questionable that the infrastructure will exist to load-out, transport, and deliver the coal product to utility sites. [EPA-HQ-OAR-2009-0491-2733.1 p.4
It is imperative that the final Transport Rule does not preclude Dairyland Power from the flexibility to procure coal from a range of suppliers and mines in the PRB. We urge the EPA to take our comments into consideration when finalizing the Transport Rule S02 allocations and direct control alternative S02 emission rates for John P. Madgett (B1).  [EPA-HQ-OAR-2009-0491-2733.1 p.4]
III. Genoa (1): The EPA's Proposal For S02 and NOx Allocations and Direct Control Alternative S02 and NOx Emission Rates Fail to Take Into Account the Boiler Design Heat Input and Will Result in a Significant Loss of Electric Output Capacity From the Unit. [EPA-HQ-OAR-2009-0491-2733.1 p.4]
In Attachment 1, Dairyland Power proposes revisions to the 2012 and 2014 S02 and NOx allocations and direct control S02 emission rates for Genoa (1). In making these allocations, the EPA has erroneously assumed 100% PRB quality coal for the basis of crafting the proposed 2012 and 2014 S02 and NOx allocations and direct control alternative S02 and NOx emission rates. Typically, the Genoa (l) unit has been fueled with a blend of bituminous coal and subbituminous coal. Historically, the blend ratio, and corresponding resulting boiler heat input, was determined by the need to match unit electrical output to system electrical demand; while preserving the capability to 'blend-up' to a high heating value coal to attain typical maximum output capacity during periods of peak system demand. It is only during the recent economic recession that slack system demand caused Dairyland Power to alter the historical fueling strategy of bit/subbituminous 'blend' fuel to one of burning 100% PRB coal during so-called 'shoulder' season months - a time that typical lower electric demand due to seasonal factors was pushed even lower due to factors related to the economic recession. [EPA-HQ-OAR-2009-0491-2733.1 p.4]
It is expected that the economy will recover from the recent slump and, along with it, return to historical electrical demand. It is expected that the Genoa (l) unit will again be needed to produce the maximum electrical output corresponding to the unit design; a capacity which can only be achieved with a greater heating value coal blend than with straight 100% PRB coal. [EPA-HQ-OAR-2009-0491-2733.1 p.4]
Dairyland Power's experience with fueling the Genoa (l) unit with 100% PRB coal results in an electric output capacity reduction of approximately 23% to 28% resulting from the reduced boiler heat input. Making modifications to the tmit to alleviate the electric output derate associated with lower heating value of 100% PRB coal may be considered by some staff at EPA to be a physical change triggering NSR/PSD permitting requirements. [EPA-HQ-OAR-2009-0491-2733.1 p.4-4]
The 23% to 28% derate in maximum unit electric output capacity of the Genoa (1) unit on 100% PRB coal is the equivalent of a 90 to 110 gross MWe generating unit. This magnitude of lost generating capacity is significant to a small rural electric cooperative like Dairyland Power which has a small portfolio of generating assets. It is infeasible at this point in time for Dairyland Power to build replacement generating capacity by 2012. Dairyland Power would face a very constrained timeline to attempt to contract for replacement capacity between the time of rule promulgation and 2012. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
The Genoa (1) unit can not meet the EPA's proposed S02 and NOx allocations and direct control alternative S02 and NOx emission rates and achieve the unit's full electric output capacity. We urge the EPA to take our comments into consideration when finalizing the Transport Rule S02 and NOx allocations and direct control alternative S02 and NOx emission rates for Genoa (1). [EPA-HQ-OAR-2009-0491-2733.1 p.5]
IV. Elk Mound Unit 1 and Elk Mound Unit 2: The EPA's Failure to Propose Any S02 and NOx Allocations and Direct Control Alternative S02 and NOx Emission Rates is an Indication That EPA's IPM Model is Flawed and Does Not Reflect the Reality That These Units Do Dispatch in the Midwest ISO Market. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
Since Dairyland Power joined the Midwest ISO in June of2010, Elk Mound Unit I and Elk Mound Unit 2 have operated at a significantly higher capacity factor than recent past years. The Midwest ISO is dispatching these units for 'reliability dispatch' rather than 'economic dispatch.' The units are geographically located in a 'transmission constrained' area, and even though these units would not otherwise be called upon to operate in a strict economic model, they are called upon to operate to relieve a transmission constraint. This is an example that EPA's IPM model fails to take into account real-world generation supply and transmission grid limitations. Dairyland Power's energy supply planning model has these units continuing to dispatch in future years and, therefore, it is imperative that these units receive S02 and NOx allocation and direct control alternative S02 and NOx emission rates in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
We urge the EPA to take our comments into consideration when finalizing the Transport Rule S02 and NOx allocations and direct control alternative S02 and NOx emission rates for Elk Mound Unit 1 and Elk Mound Unit 2. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
Response:
Thank you for your comment.Organization: Dayton Power and Light Company (DP&L)
Comment:
Dayton Power and Light Company (DP&L)
DP&L has invested hundreds of millions in environmental controls that significantly reduce air emissions in a region already hit hard by the recession. DP&L requests that EPA not inordinately minimize allowance allocations to those who have invested in air pollution control equipment, in order to provide extra allowances to those who have not. [EPA-HQ-OAR-2009-0491-2637.1, p. 2]
DP&L, like UARG, also favors aspects of the EPA's 'preferred option,' specifically allowing interstate trading on at least a limited basis and EPA's decision to issue, not auction the allowances. [EPA-HQ-OAR-2009-0491-2637.1, p. 3]
Allowance Budgets Should Align with the Capabilities of Currently Operating NOx Control Equipment
For the reasons set forth below, DP&L recommends that the EPA consider and adopt one of two potential modifications to its proposed rules with respect to the NOx emissions budgets. Item #1 is the approach preferred by DP&L. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
1. State Implementation Plans to Reduce Interstate Transport. EPA should closely comply with the 1990 CAA and allow the states to develop SIPs that would include the apportionment of Ohio's NOx transport tonnage cap in an appropriate manner to affected sources. Ohio would also be able to include alternative approaches in its SIP to address the contributions from local emissions sources to any non-attainment area. 2. Federal Implementation Plans to Reduce Interstate Transport. If Ohio allocations are made through a Federal Implementation Plan ('FIP') at the EGU level as proposed, EPA should model with a NOx floor of 0.10 pounds per mmBtu. This level is in line with the median design of SCR infrastructure and New Source Review ('NSR') consent agreements. Such a floor would adjust the allocation method to the extent necessary to ensure that the NOx emissions budgets for base loaded coal units would not drop below 0.10 pounds of NOx per mmBtu. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
The NOx SIP Call, which preceded the CAIR rule, was intended to address ozone nonattainment due to the interstate transport ofNOx emissions. In Ohio, allowances were distributed by the state on a historical heat input basis that yielded approximately 0.15 pounds of NOx allowances per mmBtu. The NOx SIP Call further projected a year when this would be reduced to approximately 0.12 pounds of NOx allowances per mmBtu. Not surprisingly, the utilities who were contemplating the installation of SCRs had SCR's designed and installed to meet the then-current standards, with the flexibility to install additional equipment or make modifications that would permit the utility to meet a future standard of approximately 0.12 pounds. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
Recent consent decrees with major utilities approved by the EPA have instituted limits of 0.12 Ib/mmBtu and 0.10 lbs per mmBtu for units with SCRs, which appears consistent with the expectations of the CAIR program. DP&L is subject to a consent decree under which it is required to meet 0.10 lbs per mmBtu limit at its Stuart Station by January 2015. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
EPA's methodology, however, results in an unrealistic emissions budget level for the Stuart Station of less than 0.06 pounds of NOx per mmBtu beginning in 2012. If the EPA was to use existing information related to currently operating equipment there is every reason to believe that the values settled upon would be in the range of 0.10 to 0.12 pounds per mmBtu. Yet, EPA proposes a value significantly lower. It is not clear at this point what operational and structural changes would be necessary at Stuart Station to operate at such levels. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
The end-result is equally unrealistic for the Killen Station. The Killen SCR was designed to achieve 0.12 pounds ofNOx per mmBtu. That emission level was well suited to all previous NOx trading programs in Ohio and Ohio's CAIR transport allocation. The proposed rule provides Killen a budget allocation that assumes that it could operate at less than the 0.06 pounds ofNOx per mmBtu level, far below its current capability. Structural changes and an intensive catalyst replacement program would be necessary to approach these levels on a consistent basis. Operating flexibility (such as aligning with reduced load at night) might become incompatible with SCR operating temperature requirements. [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
The 0.06 pounds per mmBtu level is also inexplicable when compared to the allowance allocations of the CAIR program. CATR reduces the amount of NOx allowances that would be provided to Killen and Stuart Stations by over 60% as compared to the amount of allowances that was to be provided under the CAIR program. US EPA has not fully explained the rationale for these reductions in NOx allowances, given that Ohio is a state in which the overall NOx cap remains relatively steady between the two programs. [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
Response:
Thank you for your comment.Organization: Detroit Regional Chamber
Comment:
Detroit Regional Chamber
Innaccurate, outdated data has also skewed state and electric generating unit budget allocations by failing to account for emmision reductions since 2005. [EPA-HQ-OAR-2009-0491-2720.1, p.1]
Response:
Thank you for your comment.Organization: Dominion
Comment:
Dominion
Unlimited Banking of Allowances [EPA-HQ-OAR-2009-0491-2715.1, p.3]
EPA's proposal allows banking of allowances beginning in 2012 and thus recognizes the importance of environmental and economic benefits of allowance banking. We support this concept. The ability of sources to use banked allowances for compliance provides an incentive to make early reductions, to the extent that cost-effective early reductions are possible. [EPA-HQ-OAR-2009-0491-2715.1, p.3]
Retention of Allowances from Unit-Shutdowns or Retirements for 6 Years [EPA-HQ-OAR-2009-0491-2715.1, p.3]
We support EPA's approach that would continue to allocate allowances to non-operating and/or retired units for six years. This option provides an incentive to affected entities to retire older units for which retrofit installations would not be economically feasible as acompliance option. We also support EPA's proposed approach to allocate the allowances that would have otherwise been allocated to the retired unit to the state's new source set aside (each year beginning in the seventh year after unit retires) as a means of increasing the new source set aside over time. [EPA-HQ-OAR-2009-0491-2715.1, p.3]
New Source Set Aside [EPA-HQ-OAR-2009-0491-2715.1, p.3]
We support EPA's proposal to set aside a percentage of each state's budget (under each of the emissions budget trading programs) for distribution to new sources. In addition, we support the proposed approach to redistribute any unused allowances from the new source set aside to existing sources on a pro-rata basis in proportion to each existing unit's original allocation following each control period. We request, however, that EPA record allowances for new units by June 30th of each year (instead of the proposed date of September 1st) for the annual S02 and NOx programs and May 1st (instead of the proposed June 1st) for the ozone season NOx program so facilities have assurances oftheir allocations as quickly as possible for compliance planning purposes. [EPA-HQ-OAR-2009-0491-2715.1, p.3]
Decision not to Auction Allowances [EPA-HQ-OAR-2009-0491-2715.1, p.4]
We strongly agree with EPA's proposal to provide direct allowances to affected sources and not to auction allowances. The purpose of the Transport Rule is to reduce those emissions deemed to 'contribute significantly' to downwind nonattainment. Under the proposed regulation, each source is capped at a level that EPA has determined is necessary to eliminate its 'significant contribution' and is granted allowances (free of charge) to emit to that level. Sources that choose to emit above their cap must purchase additional allowances to do so. The use of auctions inappropriately forces affected sources to purchase allowances not only for emissions that exceed their capped emission levels, but also for the right to emit at levels below these levels. However, as noted briefly above and discussed in more detail below, we have serious concerns with assumptions EPA used in establishing unit allocations in the proposal. [EPA-HQ-OAR-2009-0491-2715.1, p.4]
EPA Should Allow Trading Across the SO2 Zones [EPA-HQ-OAR-2009-0491-2715.1, p.5]
EPA should consider allowing trading across the Group 1 and Group 2 S02 states, particularly during the first two years of the proposed program when emission reduction requirements are, according to EPA, established on the same basis. First, it appears that EPA's analysis of state emission and downwind nonattainment linkages used to determine the 'Group 1 states' that would require additional S02 reductions beginning in 2014 did not take into account the impact (benefit) of emission reductions required and expected to be achieved (in both upwind and downwind states) during the initial 2 years of the program. This raises question as to the necessity, level and geographic make-up ofthe Phase 2 requirements. Second, the grouping of states into different zones complicates compliance planning and could disadvantage companies that have generation assets spread across the 2 different regions, particularly if the majority of assets are concentrated in one trading region and a few others become 'isolated' in the other trading region. For example, Dominion owns and operates electric generating facilities in 7 states that will be subject to the Transport Rule as proposed. All of these assets withthe exception of 2 facilities are located in Group 1 states. Therefore, the Company's compliance for the 2 facilities in the Group 2 state will not be able to include the use of excess allowances (to the extent available) from its larger fleet in the Group 1 states as aviable option and may require potentially more costly acquisition of allowances from the open market or unit curtailments. This issue is amplified by a significant shortfall ofallowances allocated to these facilities in 2012 and 2013 under the proposed rule as a result of erroneous IPM model input assumptions used in establishing the state budgets (discussed in more detail in Section III below). To the extent EPA is concerned about impacts of trading across the 2 zones in 2014 and beyond when the tighter reductions are required in the Group 1 states, EPA is proposing to impose the assurance provisions of the that should serve to limit the amount of 'out-of-state' allowances used for compliance by affected sources in a Group 1 state regardless of whether those allowancesare generated in Group 1 or Group 2 states. [EPA-HQ-OAR-2009-0491-2715.1, p.5]
Response:
Preamble Sections VII.D and XI provide detail on the schedule for recording allowances under the final Transport Rule and EPA's reason for choosing that schedule.
Organization: DTE Energy Services (DTEES)
Comment:
DTE Energy Services (DTEES)
Relief for stranded units
As discussed below DTEES owns several facilities that are subject to the proposed Transport Rule, but have received zero allowances. DTEES considers these units stranded units because they are small units with no facilities owned by the same parent company with which allowances can be shared and emission rates can be averaged. DTEES is not confident that there will be a robust allowance trading market for Transport Rule, and as a result, these units will be unable to secure allowances at a reasonable price, or perhaps not at all. Is it EPA's intention for units such as these to shut down? DTEES believes EPA should allocate States' additional allowances for the purpose of creating a hardship set aside pool. [EPA-HQ-OAR-2009-0491-2699.1,p.2] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.1]
Response:
Thank you for your comment.Organization: Dynegy, Inc.
Comment:
Dynegy, Inc.
EPA's proposed allocation of SO2 allowances is based on the Agency's assumptions regarding reductions that could be achieved by 2012. In order to achieve such SO2 reductions from a FGD, that FGD must be constructed and placed into operation prior to 2012. [EPA-HQ-OAR-2009-0491-2698.1, p.3]
IPM-Modeled Outcomes Do Not Reflect Actual Source Operations
IPM predicted that the vast majority of dual-fuel oil and gas units would run exclusively on natural gas. Therefore, EPA did not allocate any SO2 allowances to dual fuel units. Apparently, IPM concluded that it was most 'economical' to run these units on natural gas and failed to consider seasonal constraints on natural gas supply. Shortage of natural gas supply during winter months, especially in the Northeast, is a real concern and is one of the primary reason these units have dual-fuel capability. The reality is that many of these units burn oil during winter months and need to do so to ensure a reliable electric supply. This is specifically the case with Dynegy's Roseton Units 1 and 2 located in Newburgh, NY. [EPA-HQ-OAR-2009-0491-2698.1,p.6]
In addition, IPM projects early retirement of our Danskammer Units 1 and 2 (dual-fuel oil and gas units located in New York) by 2014, but Dynegy does not have any plans to retire these units by 2014. It is unclear why EPA has made such a unilateral decision without recognizing the continued need for these units during periods of high peak demand to support the reliable supply of electricity, a vital role they have played many times during their past history of service. [EPA-HQ-OAR-2009-0491-2698.1,p.6]
Allowance Allocations Should Not Disadvantage Well-controlled EGUs
EPA's proposed allowance allocation methodology would not only reward high emitters and punish well-controlled EGUs, but also encourage increased operation of higher emitting EGUs relative to well-controlled EGUs. Rather than promoting such an inequitable result and its associated adverse implications for air quality, EPA should modify its allowance allocation methodology to ensure that allocations do not disadvantage well-controlled EGUs relative to higher emitting EGUs. [EPA-HQ-OAR-2009-0491-2698.1, p.6]
Impact on Operating Cost
EGUs are typically dispatched based on operating cost with the least expensive units dispatched more than higher priced units. An EGU's operating cost includes the price of fuel and operating efficiency, along with several environmental factors including the cost of chemicals used to control emissions, the cost to dispose control system by-products, and the cost of emission allowances. For example, units with scrubbers incur significant expenditures for chemicals (e.g., lime or limestone) and auxiliary power, as well as significant expenses associated with byproduct disposal. In fact, the byproduct disposal for scrubbed units will increase dramatically if EPA regulates scrubber material under RCRA Subtitle C. Likewise, units with SCRs incur significant expenses associated for ammonia and catalyst replacement. [EPA-HQ-OAR-2009-0491-2698.1,p.6]
Because these well-controlled units incur significant additional expenses that are not incurred by uncontrolled units, the higher-emitting, least controlled units are, aU things being equal, dispatched more. [EPA-HQ-OAR-2009-0491-2698.1,p.7]
EPA's proposed allowance allocation methodology would further encourage higher capacity factors for the least controlled and higher emitting units that do not have as many environmental costs. Specifically, EPA would allocate relatively few SO2 and NOx allowances to well-controlled units, but allocate relatively few SO2 and NOx allowances to units with higher emissions rates. Thus, these higher emitting units that do not have costs for SCRs or FGDs could enjoy a two-fold competitive advantage over well-controlled units equipped with both an SCR and FGD. [EPA-HQ-OAR-2009-0491-2698.1,p.7]
EPA's IPM model has attempted to consider these numerous economic impacts when predicting unit heat inputs. Since EPA does not have unit-specific operating costs, numerous and broad assumptions have been used in IPM. EPA's assumptions produce significantly different and often lower operating predictions than Dynegy's internal commercial business model. Rather than relying on either simulation model, Dynegy recommends EPA use representative historic unit heat input or gross electrical output to allocate emission allowances (see Dynegy Comment 3.b below). [EPA-HQ-OAR-2009-0491-2698.1, p.7]
Alternative Allocation Methodology
Instead of rewarding higher emitting EGUs through its proposed allowance allocation methodology and projected heat inputs, EPA should allocate allowances to all fossil-fuel-fired EGUs based on each source's proportional share of historic total state heat input or gross electrical output. This alternative allowance allocation approach is similar to EPA's alternative methodology discussed in the preamble (75 Fed. Reg. at 45311) and would create an opportunity for well-controlled units to recover a portion of their operating costs and at the same time create an incentive for higher emitting units to lower their emissions, except that it would rely on historic operating levels instead of predicted future operations. This would effectively impose the cost of buying allowances on less controlled sources making their operational cost nearer to that of the well-controlled sources. Or in EPA's words ''this alternative method for distributing allowances would have the effect of distributing the responsibility for eliminating all or part of a state's overall significant contribution and interference with maintenance to individual units', 75 Fed. Reg. at 45311 , rather than focusing that responsibility on the well-controlled units. This alternative allocation method, similar in concept to EPA's Acid Rain allowance allocations, would create a level playing field for all sources by not rewarding high emitting units with extra allowances and not penalizing well-controlled units with low allocations. [EPA-HQ-OAR-2009-0491-2698.1,p.7]
Voluntary Early Compliance or Over-Compliance Should Not be the Basis for Lower NOX Allowance Allocations
From 2005 through 2009 Dynegy voluntarily operated its SCR-controlled units well below all applicable NOx limits. As proposed, the Transport Rule would inexplicably penalize Dynegy for voluntarily having achieved addit ional NOx reductions at its SCR units by allocating approximately 60 percent fewer annual and ozone season NOX allowances to these units than would otherwise be allocated if Dynegy had only met its enforceable NOx emission limits. Other EGUs that voluntarily over-controlled would be similarly penalized. [EPA-HQ-OAR-2009-0491-2698.1,pp.7-8]
EPA's use of the lowest NOx rates ever achieved at such voluntarily over-controlled units to determine NOX allowance allocations would also have other negative impacts. For example, it would indirectly hinder compliance flexibility by eliminating a possible source of tradable allowances. More specifically, it would essentially eliminate Dynegy's ability to generate any NOX allowances it will need for compliance at its other units in Illinois, thereby limiting compliance options and increasing compliance costs. Moreover, basing Transport Rule NOX allowance allocations on these previous voluntary over-control efforts would perpetuate the need to use disproportionately large quantities of ammonia at Dynegy's SCR-controlled units, more than 500 tons of ammonia per year for each SCR-controlled unit and much more than needed to comply with the federally enforceable NOX limits. [EPA-HQ-OAR-2009-0491-2698.1, p.8]
In short, EPA's proposed allocation methodology is poor environmental policy in that it would punish EGUs that have installed and operated state-of-the-art pollution control systems beyond applicable requirements, while rewarding those EGUs that have lagging environmental performance. It also would create a disincentive for an affected facility to go beyond its minimum compliance requirements. [EPA-HQ-OAR-2009-0491-2698.1,p.8]
Dynegy, which owns and operates EGUs in several affected states, supports EPA's proposal to allow interstate allowance trading. While Dynegy would prefer unlimited interstate trading to the extent permitted by the Clean Air Act, even EPA's proposed limited interstate trading as described in its Preferred Remedy Option would improve compliance costs. Limited interstate trading would give companies such as Dynegy the flexibility to decide where to make its most cost effective emission reductions and then move allowances between its units 9within the proposed variability limits) rather than purchasing allowances from other out-of-state sources. [EPA-HQ-OAR-2009-0491-2698.1, p.8]
In the event EPA does not defer to effective date of the Transport Rule until 30-36 months after promulgation, Dynegy strongly supports EPA's proposal for unlimited intrastate trading and no variability limits prior to 2014. Such compliance flexibility will be essential for effective transition to the Transport Rule program. [EPA-HQ-OAR-2009-0491-2698.1, p.8]
Dynegy Supports EPA's Decision Not to Auction Allowances [EPA-HQ-OAR-2009-0491-2698.1, p.8]
Although Dynegy does not support the intrastate-only trading option, in the event that EPA promulgates a final rule based on the option, EPA should not enable or endorse government-run allowance auctions. Governmental auctioning of allowances would substantially increase the cost of the Transport Rule upon regulated entities, adding to viability concerns for many units and, thus, ultimately increasing costs to consumers and decreasing the reliability of electric supply. [EPA-HQ-OAR-2009-0491-2698.1, pp.8-9]
Response:
Thank you for your comment.Organization: East Kentucky Power Cooperative
Comment:
East Kentucky Power Cooperative
EKPC General Comments [EPA-HQ-OAR-2009-0491-2776.1, p.5]
EKPC strongly urges EPA to allow electric generating units to bank SO2, annual NOx and Ozone NOx allowances as well as to carry over banked allowances from the CAIR program. EKPC also strongly urges EPA to clarify that should a unit be permanently removed from service, the allowances from that unit are the property of the unit owner. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
As is true of many electric utilities, over the past number of years EKPC has invested heavily in emissions reductions at its facilities. Utilities such as EKPC should not now be penalized for those emission reductions efforts by receiving lower allocations as a result reductions achieved. This rule has the potential to ultimately result in the permanent removal from service of many units, in a significantly short time frame that would severely impact the grid system which powers our homes and cities. Further, thousands of jobs could potentially be eliminated in the electric utility industry due to unit and plant closings. Such implications should be seriously considered by EPA in finalizing the rule. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
Response:
In Preamble Section IX.A, EPA provides its rationale for not allowing allowances from the CAIR programs to be used to comply with the Transport Rule.
Organization: Edison Electric Institute (EEI)
Comment:
Edison Electric Institute (EEI)
EEI supports EPA's proposal for allocating emission allowances under the preferred approach no later than September 1, 2011 for control periods in 2012, 2013 and 2014, and to allocate for future years starting on July 1, 2012 for the 2015 period, and on July 1 for each control period thereafter. [EPA-HQ-OAR-2009-0491-2697.1, p.16]
While supporting the referred approach, EEI offers the following additional input
There are different views amongst EEI members on the most appropriate allocation methodology. Some companies support EPA's proposed methodology, while others will advocate for use of alternate methodologies.  [EPA-HQ-OAR-2009-0491-2697.1, p.17]
EPA's preferred approach prohibits the usage of banked Title IV, NOx SIP Call and CAIR allowances. EEI recognizes the legal challenges to incorporating these allowances in the Proposed Rule and, indeed, some EEI member companies support EPA's preferred approach. However, some EEI member companies observe that they have installed pollution control equipment to comply with CAIR and reduced emission below their allowance allocations. These companies believe the preferred approach proposed by EPA, in effect, penalizes them by stranding their banked allowances, They emphasize that many of those banked allowances exist due to overcompliance by the affected utilities and represent additional costs incurred by the companies and their customers. If the preferred interstate trading program is finalized as proposed, such an approach by EPA would send a negative message regarding overcompliance with any future regulation. Therefore, these companies would support an equitable approach to continued use of such banked allowances. [EPA-HQ-OAR-2009-0491-2697.1, p.17]
EEI supports EPA's proposal not to require a government-run allowance auction of the entire inventory of allowances under the preferred remedy option. Governmental auctioning of allowances is contrary to the principle that regulated sources should be permitted to emit up to their allowance allocation levels without any obligation to pay for the right to emit up to those levels. Some companies have suggested, however, that a small government auction, along the lines of the auctioning of a small number of allowances under the Acid Rain Program, may be necessary given the restrictions on trading contemplated under the preferred approach which may inhibit market formation. Such an auction could help provide the market with a price signal and liquidity, which may be important to support the market, especially in its early stages. [EPA-HQ-OAR-2009-0491-2697.1, p.17]
[This comment was also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.28.]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.29.]
EEI is also concerned that trading restrictions between Group 1 and Group 2 facilities can pose a problem for some of our other members with service territories that cross state lines but where facilities lie within the same air shed.
Response:
EPA appreciates the suggestion from EEI regarding the inherent value in allowance auctions, but the Agency also notes that the commenter does not provide any technical basis for its suggestion that the proposed Transport Rule's preferred approach for interstate trading would require such auctions to operate effectively.  EPA notes that the small auctions conducted in the Acid Rain Program were intended mainly to ensure access to allowances for new units under that trading program, whereas the Transport Rule includes new unit set-asides to ensure that new units will have access to allowances under this rule's air quality-assured trading programs.
Organization: Electric Energy, Inc.
Comment:
Electric Energy, Inc.
The proposed Transport Rule will require SO2 emission reductions beyond what is required by the CAIR rule. Because the transport rule only allows intrastate allowance trading, we expect there will not be sufficient cost effective allowances available within the state of Illinois to meet EEl's compliance needs without additional pollution controls. This will require installation of SO2 control equipment beyond what is currently planned after the Transport Rule is final. The amount of additional control will be dependent on what is required by the final Transport rule. [EPA-HQ-OAR-2009-0491-2628.1, pp.1-2]
II. The use of IPM to assign allocations on a unit by unit basis is inappropriate
We do not believe it appropriate to use the IPM model to allocate allowances to the individual units in the state. The allocation should be based on historical utilization as was done in the NOx SOP rule and CAIR. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
Response:
EPA notes that interstate trading of allowances is allowed in the final Transport Rule.
Organization: Empire District Electric Company (Empire District)
Comment:
Empire District Electric Company (Empire District)
EPA's preferred approach established Group 1 and Group 2 states for SO2 emission control.  Empire District is considered a relatively small electric utility.  Our contiguous service territory is bisected by the state line between Missouri, a Group 1 state, and Kansas, a Group 2 state.  Under the preferred approach, trading is not permitting between Kansas and Missouri generating facilities.  This would result in our Riverton, KS Power Station and Asbury, MO Generation Station being prohibited from trading SO2 allowances even though they are only 25 miles apart and only 5 miles apart on a north-south basis.  In addition, our State Line Generating Station west of Joplin, MO, is located just 5 miles due east of our Riverton Generating Station  This makes no logical scientific air shed sense in the regional control of SO2 and certainly is financially harmful to Empire District and its customers.  We recommend that EPA consider allowing the trading of SO2 allowances between emission units that are owned by the same local distribution utility with a contiguous service territory whose contiguous service territory is bisected by a Group 1/Group 2 state line.  Units owned by such a utility that are not located within the contiguous service territory or air shed should be excluded.  This is a very important issue for Empire District and like utilities bisected by a Group 1, Group 2 state line.  State budgets should not be penalized for such contiguous service territory trading.  However, Empire District understands that this could create issues with the court ruling.  If a direct change cannot be made to address this issue, we recommend that EPA have the ability to grant a utility a specific waiver in circumstances where two or more facilities of such a utility are within close geographical proximity but in different states.  With appropriate adjustments, as mentioned above, to the proposed variability rule such a waiver should not create a state compliance problem. [EPA-HQ-OAR-2009-2659.1, pp.5-6]
Response:
EPA appreciates the comments regarding the geographic relationship of common airsheds and state boundaries.  In many respects, important elements of the natural environment cross administrative jurisdictions such as state borders.  EPA is authorized to require emission reductions to eliminate significant contribution to nonattainment and interference with maintenance from each upwind state under CAA section 110(a)(2)(D) and does not have the ability to vary the requirements of that statutory provision, particularly where the Court has interpreted the statute to require the Agency to define and eliminate significant contribution at the state level.  EPA does not believe it is unreasonable or unprecedented for a utility to have differing regulatory requirements at facilities located in different states; indeed, electricity regulation is routinely designed at the state level and utilities with service territories covering multiple states are clearly adept at managing the provision of electricity in each state in accordance with the laws and regulations affecting a facility within a given state.  EPA sees no meaningful basis to consider a "waiver" for the requirements on any given facility simply because the owner or operator may own or operate facilities in another state, whether or not that state is geographically adjacent; such considerations are irrelevant to the establishment of state budgets under the Transport Rule to satisfy the Clean Air Act's mandate in section 110(a)(2)(D) to eliminate significant contribution to nonattainment and interference with maintenance from each upwind state.
Organization: Environmental Energy Alliance of New York, LLC
Comment:
Environmental Energy Alliance of New York, LLC
EPA's treatment of New York in the Transport Rule runs counter to previous rule makings. On page 106 of 1361 of the preamble, EPA discusses other factors used to determine the reasonableness of upwind control obligations in other rules. EPA noted that "in general, areas that currently have, or that in the past have had, nonattainment problems ... have already incurred ozone control costs." As noted earlier, not only have New York EGU's incurred ozone control costs for Federal programs, New York only acid deposition reduction rules have resulted in significant emission reductions and required additional control costs. The emissions data and Transport Rule projections indicate that EPA's methodology apparently does not recognize the resulting emission reductions. Consequently, the Transport Rule is proposing a NY budget allocation that includes additional reductions on top of the controls already implemented. As a result, EPA's projected "highly cost effective" reductions may not be as cost effective and New York EGU sources may not have cost effective controls available. It is not likely that New York EGU facilities can meet the resulting allowance allocations without curtailing operations at some facilities because the IPM projections for additional controls and operations are not consistent with historical operations and projections for cost-effective controls. [EPA-HQ-OAR-2009-0491-2638.1, p.3]
Therefore the Alliance recommends the following:
-Revise the unit-specific allocations to be based on three-year average heat input; and
-Allow adjustments to allocations to credit New York State for its emission reduction programs to get the state budget right.   [EPA-HQ-OAR-2009-0491-2638.1, pp.4-5]
Response:
EPA includes all known and legally applicable emission control requirements in its baseline power sector modeling; therefore, EPA has already "credited" states for their pre-existing emission reduction programs (except CAIR, as explained in section V.B of the preamble) before the Agency then analyzed whether additional emission reductions would be necessary from each state to eliminate significant contribution to nonattainment or interference with maintenance of the relevant NAAQS in a downwind state..
Organization: EquiPower Resources Corp.
Comment:
EquiPower Resources Corp.
The Transport rule unfairly penalizes certain electric generating units ("EGUs"). The Rule's variability and assurance provisions cause regulatory uncertainty because of their look back enforcement provisions, which will result in sources retaining allowances instead of trading them, further hampering what limited emissions trading might occur under the rule. Similarly, the Proposed Rule's aggressive and inaccurate assumptions penalize early sources and states that were early adopters of emission controls. [EPA-HQ-OAR-2009-0491-2704.1, p.2]
Under CAIR, EPA set presumptive average emission rates that had to be achieved uniformly bysources throughout the CAIR region, and set state-wide budgets on that basis. States then allocating allowances to sources within their jurisdictions using either an input- or an output-based allocation methodology. Although the reductions were stringent and the timetable aggressive, all sources essentially were treated equally. Sources could trade allowances freely, enabling companies to make rational choices about which units should receive controls and which should not. Here, in contrast, EPA has make assumptions about the level of control which it believes each unit should achieve  -  i.e., EPA has decided which units should install controls  -  and has made individual unit allocations based on those assumptions. Moreover, unlike CAIR, which permitted unlimited trading among sources in the covered states, allowing emissions reductions to be obtained from the lowest cost sources first, the Transport Rule imposes hard state-level emission caps (subject to very limited variability provisions) that provide a hard ceiling on the aggregate emissions from affected EGUs. In effect, then, the combination of EPA's allocation approach and its state-level emission caps means that, if EPA assumed that a unit would install a certain control technology, that unit must install that control technology, because the state-level emission cap will make trading essentially unavailable (except for within-company trading where the company has several plants located within the same state  -  i.e., intra-company/intra-state trading). [EPA-HQ-OAR-2009-0491-2704.1, p.5]
The statewide caps (even accounting for the variability limits) represent a dramatic disincentive to trading because, under the Rule, if a state cap is exceeded, then all sources within the state are penalized on a 2-to-1 basis for their proportional share of the emissions exceedance. Moreover, sources cannot know contemporaneously whether or not the state cap will be exceeded, as variability is assessed retrospectively on an annual basis initially and then using a three-year rolling average.12 These penalty provisions mean that, in addition to holding allowances equal to annual NOX and SO2 emissions, a source needs to hold extra emission allowances in reserve to account for the contingency that a state's emission cap (plus variability limit) will be exceeded and that the source will be subject to a penalty. The potential for the state cap to be exceeded creates strong disincentives to trading; that is, it makes sources more likely to retain allowances instead of trading them, and as a result, sources will be forced to reduce emissions to levels that are equal to their initial allocations, such that the Transport Rule looks more like a command-and-control regime in that sources are forced to simply meet the emission rates implied by their initial unit-level allocations. More troubling, unlike a traditional command-and-control regimes where emission are limited to specific rates and not aggregate emissions (i.e., a source complying with the emissions rate can emit as much as it wants), the Transport Rule effectively requires a source to comply with a specific emissions rate as established by its initial allocations and then limits its aggregate emissions unless/until the source obtains additional reductions in its emission rate beyond the implied rate contemplated by its initial allocations. [EPA-HQ-OAR-2009-0491-2704.1, pp.5-6]
In essence, then, EPA's approach not only mandates the control technology that each unit must install, it also mandates the level at which that unit can be operated into the foreseeable future. This is particularly problematic where EPA's assumptions essentially mandate that a unit install SCR or FGD; for both economic efficiency and environmental protection, those units ought to operate at maximum capacity  -  whether or not they were operating at that level prior to the Transport Rule. Instead, EPA's assumed capacity factors (and resultant allocations) will determine the degree to which these units can operate. Not surprisingly, therefore, analysts have predicted that the Transport Rule will be dramatically more expensive than CAIR (although obtaining essentially no greater environmental benefits). [EPA-HQ-OAR-2009-0491-2704.1, p.6]
Many parties have predicted that the Transport Rule, combined with mercury regulations, could result in a significant percentage of the U.S. coal fleet being at risk for shut down.13 EPA should be mindful that if these shut downs should occur, combined cycle gas plants are the most likely source to make up for the lost baseload capacity provided by those units. It is possible that gas plants would need to run at as high as 90% capacity in some areas to make up for shut downs in the coal fleet. However, since the Transport Rule restrictions are imposed on a unit-by-unit basis, these plants will not likely have the allowances needed to fully substitute for the lost baseload capacity and, given the limitations on trading, are not likely to be able to acquire them. This problem could be avoided if EPA followed the procedural mandates of the CAA and allowed states to promulgate SIPs to meet the applicable air quality standards (as described in Section IV below). At a minimum, EPA should revise its allocations to correct for this issue. [EPA-HQ-OAR-2009-0491-2704.1, pp.6-7]
The One-Size-Fits-All Approach Ignores Important Distinctions in State Regulatory Regimes [EPA-HQ-OAR-2009-0491-2704.1, p.16]
 The FIP that the Transport Rule would impose upon the states uses input-based calculations in determining allocations. However, some states, such as Connecticut, Massachusetts, and New Jersey, have already been using output-based allocations in emission trading programs for a number of years. In mandating an input-based regulation, EPA will usurp state authority to use a system that EPA itself has advocated for more than a decade. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Output-based environmental regulations are calculated on the energy output of the process, which may be electricity, thermal, or mechanical output, and take into account the emissions benefits of efficiency. Input-based regulations are calculated on the heat input of the fuel burned in the process. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
The use of an input-based calculation will lead to different allocations than an output-based calculation, which provides a greater number of allowances to more efficient plants. An example of this different outcome is provided in EPA's Output-Based Regulations: A Handbook for Air Regulators. The example considers: [EPA-HQ-OAR-2009-0491-2704.1, p.16]
a hypothetical state with emissions of 1,700 tons per year and a cap of 1,500 tons per year (a 12% reduction); [EPA-HQ-OAR-2009-0491-2704.1, p.16]
where two plants are the only sources of emissions in that state; [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Plant 1 uses 61% of the heat input and Plant 2 uses 39%; [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Plants 1 and 2 have identical output. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Under an input-based allocation, Plant 1 would receive 909 tons of allowances and Plant 2 would receive591 tons. Under an output-based allocation, each plant would receive 750 tons of allowances. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
These differences in the allocations may have a significant impact on EGUs in output-based states. Since the Transport Rule effectively dictates both the control technology required for an EGU and the level at which that unit can be operated into the foreseeable future (see section III.B. above), this difference in the allocation method (and the resulting allowance allocations) will cause disruptions in these states because EGUs have made significant investments based on an output-based system of allocations. [EPA-HQ-OAR-2009-0491-2704.1, pp.16-17]
The Transport Rule also creates a considerable disincentive for a state to promulgate a SIP to replace the Transport Rule FIP, as EPA suggests states may do. If output-based states are forced to adopt EPA's input-based method, they would be unlikely to impose upon their sources the disruption that would result from changing the allocation method back to an output-basis. EPA has provided no guidance for states to do so in any case. Thus, while EPA suggests that states may promulgate SIPs, EPA cannot assume that states will be able to do so. This is particularly problematic given that the Transport Rule presents a one-time allocation that lasts throughout the duration of the Rule. In contrast, states typically do regular re-allocations to adjust for changes in the source mix, capacity, etc. Given the predictions regarding the coal fleet shut downs that are likely to result from the implementation of the Transport Rule, re-allocations will be necessary to reflect the current status of statewide generation. Thus, EPA's one-size-fits-all approach is flawed in that it disregards the changes that are expected to occur. Additionally, in mandating an input-based method of allocations, the Transport Rule effectively throws Connecticut, Massachusetts, and New Jersey's investment and advances in emissions reductions out the window. [EPA-HQ-OAR-2009-0491-2704.1, p.17]
EPA Failed To Properly Account For Dual Fuel Combustion Units [EPA-HQ-OAR-2009-0491-2704.1, p.22]
Three of EquiPower's four facilities  -  Lake Road, Empire and MASSPOWER  -  are dual fuel units. While all three are permitted to burn natural gas, the Empire Facility can also burn ultra low sulfur diesel ("ULSD") (sulfur content 0.0015%), the Lake Road Facility can burn low-sulfur diesel ("LSD")(sulfur content 0.05%), and MASSPOWER can burn fuel oil with a sulfur content of 0.2% or less, including LSD and ULSD. In each instance the permits for these plants allow them to run for some specified number of hours using these alternate fuels. During these periods of operation, the SO2 and NOX emissions from the plant increase relative to operations burning natural gas. The dual fuel nature of these units is important from an electrical system reliability perspective. By having flexibility in the types of fuel that can be burned, these units are capable of producing power while responding to price fluctuations, supply disruptions, or supply curtailments. In fact, when some of those facilities were permitted and approved, the relevant regulators required them to have the production flexibility provided by multiple fuels because they know that periodic natural gas supply disruptions can occur (e.g., pipeline disruptions or pipeline capacity constraints) which would impair electrical system reliability if the plants were not able to burn other fuels during those periods. It is sound public policy to not have our generation capacity reliant on a single fuel source with no back up plan. Thus, while a duel fuel unit generally burns natural gas, it is permitted to burn other fuels and at times can be required to do so. [EPA-HQ-OAR-2009-0491-2704.1, p.22]
Despite the sound public policy reasons behind the dual fuel units, EPA's projected emissions for EquiPower's dual fuel facilities appear to assume 100% natural gas combustion, and as a result the facilities have been under-allocated allowances for both SO2 and NOX. EPA's failure to account for distillate fuel operation is significant given the limited allowance availability that is likely to result under23the Transport Rule. It effectively limits those facilities to natural gas only operation, and therefore it is not sound public policy because it interferes with electrical system reliability. EquiPower submits that, at minimum, dual fuel units like Lake Road, Empire and MASSPOWER, should be allocated allowances using a methodology that accounts for both their gas-fired and non-gas-fired operations. EquiPower has looked at its own units and calculated the additional SO2 and NOX emissions that would result from operating those facilities using fuel oil/diesel fuels for the maximum amount of time permitted under their permits. Table 4 [See p.23 of this comment summary for Table 4] shows the additional allowances that would be required at each facility to account for the non-natural gas operations at each facility assuming that (i) the facility burns the highest sulfur content fuel for the maximum time allowed by its permit, and (ii) it burns only ULSD for the maximum time allowed by the permit. Table 4 [See p.23 of this comment summary for Table 4] clearly shows that the failure to account for dual fuel operations, even assuming ULSD only, resulted in a significant under-allocation of allowances at these facilities (particularly for NOX) that must be corrected by EPA. [EPA-HQ-OAR-2009-0491-2704.1, pp.22-23]
Recognizing that one potential consequence of the Transport Rule is that EGUs will have to switch from higher sulfur content fuels to lower content distillates, EquiPower believes that EPA should, at minimum, adopt a phased approach to SO2 allowance allocation for dual fuel units. A phased approach for SO2 allowances is appropriate given that many of these plants, particularly older ones, are expressly allowed by their permits to burn fuels that are higher in sulfur content than ULSD and that those facilities may already have inventories of such higher sulfur content fuels. EquiPower proposes that during Phase I any dual fuel units receive SO2 allowances equal to 50% of the allowances that would be required for the maximum level of non-gas-fired operations allowed under those units' permits. In Phase II those units should receive the minimum number of allowances required for those units assuming they burn only ULSD. With respect to NOX, since those emissions are not affected by the fuel burned, EquiPower submits that EPA should revisit the NOX allowance allocations for those units and adjust them upwards to account for alternate fuel operations. Table 5 [See p.24 of this comment summary for Table 4] below presents EquiPower's proposed additions to the allowance allocations for its dual fuel units using the preceding approach. [EPA-HQ-OAR-2009-0491-2704.1, p.23]
FLAWS IN SEVERAL TRANSPORT RULE PROVISIONS UNFAIRLY PENALIZE CERTAIN EGUS [EPA-HQ-OAR-2009-0491-2704.1, p.25]
The Transport Rule Should Have Provided SO2 Allocations for Electric Generating Facilities Fueled by Natural Gas [EPA-HQ-OAR-2009-0491-2704.1, p.25]
EPA has unfairly penalized many natural gas-fueled EGUs in the Transport Rule by not allocating them any SO2 allowances despite EPA's own position that at least some SO2 is emitted from these facilities. EPA assumes, in its Optional SO2 Emissions Data Protocol for Gas-Fired and Oil-Fired Units that accompanies its regulations for Continuous Emission Monitoring,53 that some small amount ofSO2 is emitted from natural gas fueled generating facilities. The optional protocol, which may be used by natural gas-fueled units in lieu of continuous SO2 monitoring, establishes a default SO2 emission rate of0.0006 lb/mmBtu for those facilities.54 Despite its own recognition that natural gas-fired units emit someSO2, EPA appears to apply a zero SO2 emissions factor for natural gas plants for purposes of unit-level allocations under the Transport Rule. As a result, EPA allocates no SO2 allowances to natural gas-fired facilities allocated under EPA's Projected methodology. Not only is this outcome plainly at odds with the Agency's own regulations, it also potentially hampers those units' operations given the limited supply of allowances that EquiPower believes will actually be available for sale under the Rule. [EPA-HQ-OAR-2009-0491-2704.1, p.25]
This penalty is problematic based on the de minimis quantities of SO2 that EPA assumes are present in a natural gas-fired EGU's exhaust stream. Given the very low potential levels, the majority of natural gas plants do not monitor for SO2 and instead rely on EPA's default emissions rate of 0.0006lb/mmBtu as their emissions rate for SO2. Moreover, given this low level of SO2 emissions, it is impractical for natural gas plants to control for SO2, even if they chose to, because such a small amount ofSO2 could not be scrubbed or otherwise be removed cost-effectively. This problem of the lack of SO2allocations and lack of control options will be exacerbated by the Transport Rule's limited trading scheme, which will result in very limited allowance availability. Natural gas-fired units will have great difficulty in obtaining allowances, if there are even any allowances to be had (as explained in Section III.B. above). In Massachusetts, for example, all available SO2 allowances will likely be needed to address EPA's significant miscalculation in the Commonwealth's budget due to mistaken assumptions regarding Brayton Point's installation of an FGD. [EPA-HQ-OAR-2009-0491-2704.1, pp.25-26]
Therefore, EPA should revise its unit-level allocations to account for SO2 emissions from natural gas facilities. EPA should calculate an EGU's SO2 allowance using the default SO2 emission rate in EPA's regulations -- 0.0006 lb/mmBtu -- and the applicable EGU's heat input capacity rating. As explained in Section V.B.1 above, EquiPower believes that the capacity ratings for its units should be increased and that its SO2 allocations under this proposed approach should reflect those increased ratings. [EPA-HQ-OAR-2009-0491-2704.1, p.26]
The Transport Rule's State Budgets Penalize Early Adopters [EPA-HQ-OAR-2009-0491-2704.1, p.27]
By allocating allowances based on its assumptions about the types of controls that will be employed and the level of emissions reduction that will be obtained, EPA effectively penalizes sources that have taken early action on emission reductions, but as a result have existing emissions control equipment that do not necessarily achieve the control levels assumed by EPA in the Transport Rule. Given EPA's long-standing efforts to encourage sources to reduce their emissions, it cannot be the intent of the Proposed Rule to punish those sources that provided those early emission reductions. As a result, EquiPower encourages EPA to revise the Proposed Rule to ensure that the allowance allocations in the final Transport Rule do not penalize early actors. [EPA-HQ-OAR-2009-0491-2704.1, p.27]
Response:
As described in section VII.D of the preamble, EPA is allocating allowances to existing units based on historic data under the final Transport Rule FIPs.  As a result, historic emissions from duel-fuel units would accurately capture the type of operations described by the commenter to the extent they occurred at specific units over the historic baseline period used for allocation purposes.  In addition, historic emissions data for gas-fired units would accurately reflect SO2 emissions and thus provide a basis for SO2 allowance allocations to those units; these allocations are fully detailed in the Allowance Allocation Final Rule TSD.
Organization: Exelon
Comment:
Exelon
Because of the manner in which unit allowances would be distributed under the proposed rule, each revision to a state budget would require a reallocation of allowances among all of the units in the state. As discussed in Comment 8.2 below, Exelon believes that reallocation of allowance budgets unnecessarily introduces complexity, perverse operating incentives and litigation risk into what could otherwise be a simple pro rata reduction in allowance budgets. Therefore, while Exelon recognizes the validity of EPA's approach to the implementation of future NAAQS revisions and revised state budgets, Exelon urges EPA to adopt in the final Transport Rule the more streamlined methodology described in Comment 8.2 for unit allocations. The proposed methodology would also enable companies to anticipate future reductions in allocations, and thus improve their ability to plan future capital expenditures. [EPA-HQ-OAR-2009-0491-2666.1, p.13]
ALTHOUGH EPA'S PROPOSED ALLOWANCE ALLOCATION SCHEME IS CONSISTENT WITH THE REQUIREMENTS OF THE CAA, EPA SHOULD MODIFY ITS ALLOCATION SCHEME IN SEVERAL WAYS TO ALLOW EXPEDITIOUS FUTURE REDUCTIONS INSTATE BUDGETS, TO REMOVE PERVERSE INCENTIVES AND TO ENCOURAGE PERMANENT REDUCTIONS IN EMISSIONS.
EPA SHOULD ALLOCATE SOME ALLOWANCES BY AUCTION, ALLOCATE ALL FREE ALLOWANCES ON THE BASIS OF SOME COMBINATION OF HISTORICAL ELECTRIC OUTPUT AND HEAT INPUT, AND PROVIDE A CLEAR MECHANISM TO REDUCE FREE ALLOCATIONS UNIFORMLY WHEN STATE EMISSIONS BUDGETS ARE REDUCED. Exelon believes that the system for allocating allowances should comport with the following principles: (1) it should not affect investment or operating decisions of source owners or create perverse incentives; (2) it must be statutorily authorized and consistent with the legislative intent; (3) it should be based on method or metric that will not produce erroneous or anomalous results or be so unfair as to be deemed arbitrary and capricious; and (4) it should allow uniform percentage reductions in unit emissions budgets when state budgets are reduced. [EPA-HQ-OAR-2009-0491-2666.1, pp.30-31]
In particular, the key principle to any effective allowance distribution mechanism is that the distribution of allowance value be completely independent of operating, investment, retirement, or banking decisions made by entities covered by the Transport Rule and participating in the allowance trading regime. Allowance allocations must be based on a metric that is measured and fixed prior to the effective date of the Transport Rule and not updated except insofar as percentage reductions are required to meet lower state budgets (i.e., "nonupdating"). Without this independence, the rule could create incentives for source owners that are inconsistent with the goals of the rule and that distort allowance price signals. For example, if the original allowance allocation was to be updated based on electric output during the period covered by the Transport Rule (i.e., 2012 or later), source owners would face an incentive to increase output (and therefore emissions) in order to increase their future allocation of allowances. Further, the source owner would build the future value of allowance allocations into its bids to supply electric energy in competitive electricity markets, distorting price signals and causing high-emission sources such as coal to dispatch more frequently than they otherwise would. In contrast, if allowance allocations are based on a non-updating metric that is measured and fixed prior to the effective date of the Transport Rule, as is the case in the proposed rule, then these perverse operating incentives are largely avoided. [EPA-HQ-OAR-2009-0491-2666.1, p.31]
Exelon believes that the proposed Transport Rule partially satisfies these criteria but could nonetheless be improved. Exelon is concerned that EGUs may still face perverse operating incentives because the Transport Rule is silent on how allowance allocations will be adjusted when NAAQS are further revised and state budgets are accordingly adjusted. In particular, if emitters anticipate that EPA may "reset" allocations in the future based on new IPM modeling or actual emissions in the period after 2012, they may face an incentive to delay installation of pollution control equipment in the near-term in order to capture potentially a higher allocation following the "reset." On a market-wide basis, this anticipation of a future "reset" could lead to higher emissions in the near-term, less allowance banking, and market prices that do not reflect the true marginal cost of emission reduction. Exelon also believes that basing free allocations on IPM modeling is problematic because a future allocation "reset" would rely on new IPM modeling (see Comment 2.3), which would leave future state budget revisions vulnerable to legal challenges. [EPA-HQ-OAR-2009-0491-2666.1, p.31]
Given these concerns, Exelon proposes that EPA make three changes to the allowance allocation mechanism for the Transport Rule:
1. Rather than basing free allocations to EGUs on IPM modeling, Exelon proposes that allocations of free allowances be fixed based on a simple, non-updating historical metrics measured prior to the commencement of the Transport Rule. Possible metrics include historical heat input or historical electric output of EGUs regulated under the Transport Rule, either alone or in some combination. To the extent that EPA retains IPM modeling as a metric for allocations, Exelon urges EPA to provide strong assurances that the allowance allocations will not be updated in the future based on new IPM modeling. Comment 8.2, Comment 8.3, and Comment 8.5 further discuss the legal and policy basis for different metrics. [EPA-HQ-OAR-2009-0491-2666.1, pp.31-32]
2. Exelon proposes that EPA distribute a small but increasing portion of allowances via auction rather than free allocation to EGUs. Distribution via auction avoids the potential incentive problems associated with free allocations and has many other benefits as well. Comment 8.4 provides a detailed discussion of the mechanics and benefits of Exelon's auction proposal. [EPA-HQ-OAR-2009-0491-2666.1, p.32]
3. Exelon proposes that EPA augment the Transport Rule with a clear mechanism describing how allowance allocations will be adjusted to accommodate anticipated changes to the NAAQS. This mechanism should be designed so that it does not create incentives for EGUs to emit more in the near-term. Comment 8.5 describes a mechanism to accomplish this goal. [EPA-HQ-OAR-2009-0491-2666.1, p.32]
Although Exelon is suggesting several improvements to EPA's allocation method, EPA could adopt any one of them without the others. For example, it could adopt the auction proposal but not revise its method for allocating free allowances and vice versa. The benefits of these allocation options are discussed in comments related to each option. However, Exelon believes that it is particularly important to revise the allocation method because the alternatives suggested here will better facilitate the implementation of reduced state budgets in the future without creating the perverse operating incentives that would result from a re-allocation of allowances each time state budgets must be reduced. Moreover, the alternatives proposed by Exelon will eliminate the significance of any errors or anomalies in establishing unit budgets based on the IPM. The alternative methods suggested here are also more consistent with allocation methods used by EPA in the past. Use of an auction will provide additional assurance that those with concentrated market power will not be able to manipulate markets and will lower barriers to entry by new, zero or low pollution generation technologies. [EPA-HQ-OAR-2009-0491-2666.1, p.32]
FREE ALLOWANCES SHOULD BE ALLOCATED ON THE BASIS OF SOME HISTORICAL METRIC AND EPA SHOULD REMOVE ANY LINKAGE BETWEEN THE NUMBER OF FREE ALLOWANCES ALLOCATED TO A UNIT AND THE COMPLIANCE ASSURANCE PROVISIONS OF THE TRANSPORT RULE.
Exelon proposes that EPA retain IPM modeling results as a means of determining overall state budgets, but utilize a simple, verifiable historical metric to apportion free allowance allocations to individual EGUs. The historical metric could be historical heat input or historical output of regulated units, alone or in some combination. 57 The historical metric would be based on some period prior to the promulgation of the Transport Rule, such as 2009, or a three-year average covering 2007-2009. Regardless of the individual metric chosen, in each case the metric should be utilized to calculate a share for each EGU of the total allowances available for free allocations to EGUs in each state, which would be based on the overall state budget. For example, if a state has a total budget of 100 tons, of which 94 are available for free allocation, a regulated unit whose historical heat input (or output, etc.) comprised 10% of total state historical heat input would receive an annual allocation of 9.4 allowances. [EPA-HQ-OAR-2009-0491-2666.1, pp.32-33]
The compliance assurance mechanism proposed by Exelon in Comment 5 removes the linkage between free allocations and compliance assurance altogether and will most readily allow the adoption of an allocation method that will permit uniform percentage reductions in unit allocations. However, this can also be accomplished by retaining EPA's current compliance assurance mechanism and delinking unit compliance budgets and unit allocations. In that case, when a state budget is reduced, EPA could reduce allowance allocations by a uniform percentage but reduce unit compliance budgets to the emissions levels needed to achieve the budget as determined by EPA's IPM modeling. In that case, uncontrolled units would have new reduced compliance budgets potentially reflecting installation and operation of controls, while already-controlled units would have unchanged compliance budgets. [EPA-HQ-OAR-2009-0491-2666.1, pp.34-35]
[For additional comments pertaining to FREE ALLOWANCES SHOULD BE ALLOCATED ON THE BASIS OF SOME HISTORICAL METRIC AND EPA SHOULD REMOVE ANY LINKAGE BETWEEN THE NUMBER OF FREE ALLOWANCES ALLOCATED TO A UNIT AND THE COMPLIANCE ASSURANCE PROVISIONS OF THE TRANSPORT RULE see pp.32-35]
This language provides EPA with broad authority to implement any of the alternative allocation methodologies set forth above. The language generally authorizes use of "economic incentives" as one of many alternative "control measures, means or techniques." Since a cap and trade program is an incentive-based means of controlling emissions, this language authorizes a cap and trade system. The method for initially allocating allowances, therefore, is left to EPA's discretion, as long as it generally falls within the ambit of the term "economic incentives." Each of the allocation methodologies set forth above satisfies this test, although some allocation methodologies fall more clearly within the legislative intent than others. Exelon believes that the allocation methodology that it proposes herein hews more closely to the legislative intent than does the one that EPA has proposed. [EPA-HQ-OAR-2009-0491-2666.1, pp.35-36]
Specifically, because an auction of emissions allowances is specifically referenced in the statutory language, EPA would be on the soundest legal ground if it utilized an auction to distribute allowances. For this reason, EPA should utilize an auction to distribute some or all of its allowances. Because the CAA includes no restriction on using multiple incentives, an auction of some, but not all of the allowances should also be permitted. [EPA-HQ-OAR-2009-0491-2666.1, p.36]
Although EPA's proposed allocation methodology  -  giving away allowances based on either projected modeled emissions or historical emissions  -  is authorized under the statute, it has aspects that make it the most problematic of the allocation methodologies. Because it is awarding allowances based on past or projected pollution and awards the fewest allowances to those who have done the most to limit their emissions, one might argue that it is not an incentive at all. However, the CAA specifically mentions marketable permits and arguably awarding allowances based on projected or historical permitted amounts of emissions is, in fact, a marketable permit. [EPA-HQ-OAR-2009-0491-2666.1, pp.36-37]
Section 110(a)(2)(A) and the CAA's definition of FIP also provide EPA with sufficient authority to allocate allowances to all electric generating units or fossil fuel generating units based on historical electric production. If allowances are to be allocated for free, an allocation that favors zero or low pollution production techniques would advance the statutory intent of creating incentives to reduce pollution than free allocation based on pollutants emitted. 61 The statute's use of the term "economic incentives" suggests that a free allocation of allowances that gives more allowances to the facilities that produce the highest level of pollution per unit of production is inconsistent with the statutory mandate. [EPA-HQ-OAR-2009-0491-2666.1, p.37]
Finally, the statute also would authorize an allocation based on historical heat input. This would still reward plants that install pollution control equipment but would not provide as large a reward to plants that achieve emissions reductions through efficient production or use of low- or zero-pollution electric production technologies. Nevertheless, this allocation method is more consistent with statutory intent and prior EPA practice that the method set forth in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, p.37]
Thus, given the breadth of EPA's discretion, EPA could likely adopt a mix of allocation methods. Certainly, it could distribute a portion of the credits by auction and award the balance for free based on historical emissions, electric output, heat input or some combination of the foregoing. [EPA-HQ-OAR-2009-0491-2666.1, p.38]
EPA SHOULD MODIFY ITS PROPOSED ALLOCATION SCHEME TO INCLUDE AN AUCTION OF A PORTION OF ALLOWANCES AVAILABLE FOR EXISTING UNITS, AUGMENTED BY ALLOWANCES NO LONGER ALLOCATED TO RETIRED UNITS. [EPA-HQ-OAR-2009-0491-2666.1, p.38]
Exelon believes that auctioning some or all allowances is a key element to an effective cap and trade program. Accordingly, while Exelon's auction proposals are linked to a number of other changes to the allocation of allowances and the structure of the assurance provisions, Exelon believes that EPA should consider adopting its auction proposal regardless of whether the other elements of Exelon's comments are ultimately incorporated as part of the Transport Rule. Auctions are specifically referenced in the authorizing legislation and therefore should be viewed as a Congressionally-preferred method of allocation. Auctions are an exceptionally "clean" mechanism for distributing allowances in that they completely de-link EGU decisions concerning unit operations, pollution control investments and retirement from the award of financial value associated with allowances, because the financial value of the allowances is retained by the auctioning authority and does not flow to the EGUs. Auctioning some or all allowances thus helps ensure that EGUs will face proper economic incentives to comply with the goals of the proposed Transport Rule in the most economically efficient manner. [EPA-HQ-OAR-2009-0491-2666.1, p.38; For additional comments pertaining to EPA SHOULD MODIFY ITS PROPOSED ALLOCATION SCHEME TO INCLUDE AN AUCTION OF A PORTION OF ALLOWANCES AVAILABLE FOR EXISTING UNITS, AUGMENTED BY ALLOWANCES NO LONGER ALLOCATED TO RETIRED UNITS see pp.38-40 of this comment summary]
ALL ALLOWANCES THAT ARE ALLOCATED TO EXISTING UNITS FREE OF CHARGE SHOULD BE ALLOCATED BASED ON ELECTRIC OUTPUT, HEAT INPUT, OR SOME COMBINATION OF THOSE METRICS. EPA SHOULD SPECIFICALLY PROVIDE THAT UNIT ALLOCATIONS WILL BE REDUCED BY THE SAME PERCENTAGE AS STATE BUDGETS WHENEVER THOSE BUDGETS ARE REDUCED IN THE FUTURE.
Although EPA's method for allocating free allowances to existing units is permissible, as discussed above, alternative mechanisms better advance a number of important policy objectives and are more consistent with statutory intent. Exelon therefore suggests that all free allowances be allocated to existing units based on some combination of historical heat input or historical electric output from regulated units. [EPA-HQ-OAR-2009-0491-2666.1, p.40]
Exelon believes that it is essential that EPA propose a clear and uniform mechanism to reduce free allocations proportionally whenever state budgets are reduced, and these alternative historical metrics will facilitate such a mechanism. As noted in Comment 8.1, as proposed, the Transport Rule is silent on how future changes in state budgets associated with revised NAAQS will be incorporated into the allowance allocation mechanism. Exelon believes that additional clarity surrounding this issue is important to ensure an efficient emission allowance market with proper price signals for unit operations, pollution control investments, and retirement. Accordingly, Exelon proposes that EPA augment the Transport Rule with a mechanism providing that free allocations to individual EGUs will be reduced on a proportionate basis with any future reductions in state budgets. For example, if a state budget is currently set at 100 tons, and after incorporating a revision to a NAAQS, EPA determines that the state budget should be revised downward to 90 tons, the free allocations to all EGUs in that state would be reduced by 10%, regardless of any modeling or analysis performed by EPA in setting the revised state budget. However, this system could not be equitably imposed if allowances are allocated based on historical emissions, as discussed in Comment 8.2 above. [EPA-HQ-OAR-2009-0491-2666.1, pp.40-41; for additional comments pertaining to ALL ALLOWANCES THAT ARE ALLOCATED TO EXISTING UNITS FREE OF CHARGE SHOULD BE ALLOCATED BASED ON ELECTRIC OUTPUT, HEAT INPUT, OR SOME COMBINATION OF THOSE METRICS. EPA SHOULD SPECIFICALLY PROVIDE THAT UNIT ALLOCATIONS WILL BE REDUCED BY THE SAME PERCENTAGE AS STATE BUDGETS WHENEVER THOSE BUDGETS ARE REDUCED IN THE FUTURE see pp.40-41 of this comment summary]
EPA'S PROPOSAL TO ALLOW OWNERS OF RETIRING UNITS TO RETAIN ALLOWANCES FOR SIX YEARS REDUCES THE PERVERSE INCENTIVE TO KEEP HIGHLY POLLUTING UNITS IN OPERATION, BUT ALL ACTIVE UNITS SHOULD RECEIVE ALLOWANCES, EVEN IF THEY RETIRE BEFORE JANUARY 1, 2012.
Exelon notes that EPA's proposal to continue to allocate allowances to retiring units for six years blunts the perverse incentive for units to continue operation simply to receive allowances. If allowances were discontinued after a shorter period of time, units would have such an incentive. Therefore, unless EPA moves to something approaching a 100% auction for allowance allocation, it should retain this part of its proposal in order to reduce incentives to keep high pollution, low output facilities operating. [EPA-HQ-OAR-2009-0491-2666.1, p.41]
For the same reason, EPA should not create an incentive for owners who are considering, or who have announced, the retirement of units prior to January 1, 2012, to defer that retirement until after the Transport Rule goes into effect. As explained in the preamble to the proposed rule, if a unit is permanently retired prior to January 1, 2012, and thus is not required to hold allowances for compliance on that date, the unit will receive no allowances, and EPA will effectively withdraw any allowances allocated to that facility, even if they were already placed in the unit owner's account. In contrast, if a unit operates on January 1, 2012, and retires at the end of the day, that unit will be entitled to receive allowances through 2019. [EPA-HQ-OAR-2009-0491-2666.1, pp.41-42]
This concern is not hypothetical to Exelon. Exelon has announced that it intends to retire four old fossil fuel units in Pennsylvania, all of which have received a proposed allocation of allowances in the technical support document for the Transport Rule allocations. Three of these four units have proposed retirement dates before January 1, 2012. Under the current proposed rule, Exelon has a significant economic incentive to continue to operate these three units until at least January 1, 2012  --  seven years of allowances to offset one day of emissions. Yet, the policy behind the Transport Rule would be better served if Exelon retired those units as soon as possible. EPA should reward companies that have already decided to reduce pollution by closing inefficient plants, not create incentives to defer retirement. Accordingly, Exelon urges EPA to revise the final Transport Rule to allocate allowances through 2018 to units currently in operation, which are permanently retired before January 1, 2012. [EPA-HQ-OAR-2009-0491-2666.1, p.42]
EXELON URGES EPA TO ACCEPT CERTAIN TECHNICAL CORRECTIONS SET FORTH HEREIN.
As discussed in Comment 8.1, Exelon suggests that EPA not use its IPM modeling as the basis for unit allocations. Rather, Exelon proposes that EPA use an allocation system based on recent historical generating unit activity. However, should EPA elect to retain its generating unit allocation methodology based on IPM projections, Exelon recommends that EPA consider the issue of peaking units that are projected to have less than 0.5 tons of emissionsby the IPM modeling. In its current methodology, EPA utilizes a conventional rounding technique to round down units that are projected to have less than 0.5 tons of emissions to receive zero allowances. Exelon recommends that for these peaking units EPA adopt a rounding convention that "rounds up" so that such units would receive one allowance, rather than zero allowances. An allocation system based on recent historical generating unit activity would obviate the need for this accommodation to address the limitations of IPM modeling to project emissions from small peaking units that are infrequently operated, but that nonetheless do emit greater than zero emissions. [EPA-HQ-OAR-2009-0491-2666.1, pp.43-44]
57 Even an allocation based on historical emissions, as in the proposed rule, meets the primary criterion that the allocation be non-updating, although Exelon believes that heat input and electricity output are both preferable historical metrics for the reasons discussed below.
61 It also appears to fall within EPA's discretion to award allowances to regulated electric distribution companies rather than generators, the methodology that Exelon has supported with respect to award of GHG emissions allowances. Under that method, the distribution companies would receive allowances based in part on the electricity distributed by the company, regardless of the method by which the electricity is generated, and then the distribution companies would sell allowances to generators, so that customers would benefit, but the customers of electricity generating lower levels of pollution would benefit more. Although Section 110 includes restrictions on EPA's authority to require parking surcharges, and certain mobile source controls, it contains no restriction upon how EPA structures cap and trade programs, auctions and marketable permits. Indeed, limiting the award of free allowances to the regulated industry sector of the electric generation and distribution industry may be more consistent with the original Congressional intent. Congress added the authorizing language quoted above to the CAA in the 1990 Amendments, when it also created the Title IV cap and trade program to limit acid rain. In 1990, both electric generation and distribution were price regulated and consumers, rather than generating companies, would reap the benefit of the distribution of free allowances. Since that time, many states have deregulated the generation sector, while leaving the distribution companies price regulated. Indeed, it is for that reason that in the climate bill passed by the House of Representatives, the American Clean Energy and Security Act, HR 2454, the House awarded GHG emissions allowances based on electric generation to distribution companies, contemplating that they would sell them to the carbon emitters, so that carbon free generation would be favored but the award of free allowances would go to the general public. The very broad authorizing language in the CAA and its intent to incentivize pollution-free generation provides authority to employ a similar mechanism in a regulation establishing a cap and trade program.
Response:
Thank you for your comment.Organization: Florida Municipal Electric Association (FMEA)
Comment:
Florida Municipal Electric Association (FMEA)
In addition, EPA should not add provisions and new methodologies in the Proposed Transport Rule that are not designed to directly respond to the Court remand directing EPA to retain the environmental values of CAIR to the greatest degree practical. As currently proposed, the allowance allocation scheme in this rule will disadvantage utilities that have made major expenditures to add air pollution controls to meet the CAIR emission caps compared with those that have not. EPA's preferred allowance allocation option has the effect of punishing utilities that have taken early actions to comply with CAIR. [EPA-HQ-OAR-2009-0491-2731.1, pp. 1-2]
EPA's emission allowance allocations are unfair and are counter to cap and trade market based principles: The allocations proposed by EPA will be based on the "Optimized" operation of the pollution reduction equipment of each EGU. This means that a utility that installed a new flue gas desulfurization (FGD) scrubber to meet CAIR requirements that gets up to 90% or better SO2 removal would get SO2 allowances based on the equipment running at 90% or better. The same situation applies to utilities that installed new selective catalytic reduction (SCR) equipment. At the same time, EPA proposes to allocate allowances to those utilities that have not made the expensive control technology investments based on the far lower cost compliance options of using low sulfur fuels or low NOx burners. [EPA-HQ-OAR-2009-0491-2731.1, p. 3]
FMEA believes that a serious equity and fairness issue is created by the allocation methodology proposed in the Proposed Transport Rule. While the Court found fault with EPA's attempt to address equity with the fuel factor, there is no indication that the Court required EPA to go to the other extreme. A few examples illustrate this point. The Florida Municipal Power Agency (FMPA) owns and operates state-of-the-art gas-fired combined-cycle units that under CAIR would have received 448 NOx allowances. However, under the Proposed Transport rule, FMPA would receive only 70 allowances, which is insufficient to run these units without purchasing allowances. Gainesville Regional Utilities (GRU) spent $141 million to install a FGD scrubber on its Deerhaven #2 coal-fired generating unit to meet and exceed CAIR requirements. Under CAIR GRU was expected to receive about 3,136 allowances but under the Proposed Transport Rule the utility would receive 614 allowances. [EPA-HQ-OAR-2009-0491-2731.1, p. 3]
The Proposed Transport Rule allowance allocation methodology is poor public policy. First, the proposed allowance allocation methodology violates a key cap and trade success principle. The proposed allocation method fails to allow utilities to choose to over-control their emissions at electric generating units (EGUs) where it is cost-effective and under control at sources where it is less cost-effective. For example, if under CAIR an 80% removal of SO2 would achieve compliance and running at 95% removal could generate surplus allowances for sale, the Proposed Transport Rule would not allow that benefit for installing expensive pollution controls. [EPA-HQ-OAR-2009-0491-2731.1, pp. 3-4]
Second, the Proposed Transport Rule punishes aggressive early emission reductions. Unlike the CAIR rule, by reducing allowances to those who installed expensive air pollution control equipment, EPA is actually financially punishing utilities for both early compliance and aggressive emission reductions. In addition, EPA proposes that units that haven't installed any controls will get allowances based on operation with lower-cost low sulfur fuels and low-NOx burners. [EPA-HQ-OAR-2009-0491-2731.1, p. 4]
Third, the Proposed Transport Rule allowance allocation methodology will hurt future proactive emission reductions by industry. The shift away from the CAIR allocation methodology, one that rewards over-control and early-emission reductions, to the proposed Transport Rule methodology that punishes the very same behavior, will create a long-lasting chilling effect on future proactive emission reductions by industry. [EPA-HQ-OAR-2009-0491-2731.1, p. 4]
Finally, the Proposed Transport Rule allowance allocation method ignores the fact that many costly decisions were made by the utility industry based on the CAIR. To meet the CAIR compliance requirements FMEA members committed to costly emission control systems while the rule was under court challenge. Those commitments by FMEA members were based in part on the assumption that EPA would keep as much of CAIR intact as the Court would allow. In response to EPA's request for suggestions for an alternative allowance allocation method, FMEA strongly recommends that EPA allocate both SO2 and NOx allowances based on heat input at the emission rates necessary to achieve the state emission budget. Using the allocation method would not only address the Court's remands based on the fuel factor and improper use of Acid Rain SO2 allowances, it would bring fairness back to the allocation methodology. [EPA-HQ-OAR-2009-0491-2731.1, p. 4]
EPA's Use of IPM Produced Materially-Flawed Allocations. In EPA's posted "Projected Data" spreadsheet which was published with the proposed rule, FMEA realized that EPA had not allotted SO2 allowances for those units which burn fuel oil and natural gas. Following conversations with EPA representatives, FMEA understands that IPM predicted that these dual-fuel fired units will only be burning natural gas in the future. This is one of the many flaws in EPA's methods.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
First, fuel oil currently provides 16% of Florida's electric generating Summer capacity (MW) and is being assumed to represent 13% of such capacity in 2019 (Florida Public Service Commission, Fuel Diversity Workshop, August 5, 2010). Florida receives gas from only three pipelines. During the 2005 Hurricane Season, Florida nearly depleted its supplies of natural gas supplies due to interruptions in the Gulf of Mexico. During this emergency period, utilities held daily meetings to assess the situation and discuss possible contingency plans, many of which centered on utilities ability to burn fuel oil in their dual-fuel fired natural gas units. As EPA has cited in their Endangerment Finding, the U.S. should be encountering increased storm activity in the near future, and so the U.S. should plan accordingly. Assuming arguendo, this rule proposal merely pushes Florida sources to become much more reliant on natural gas, which will only exacerbate any future issues with curtailed or jeopardized gas supplies.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
It also appears that IPM predicts that coal units can and will switch to lower sulfur coals in order to meet SO2 reduction requirements. Many of the same questions apply with coal as did natural gas, namely EPA's lack of analysis on current permitted coal sulfur limits, the cost and availability of the targeted fuel, and the railroad line capacity to meet the predicted dramatic increase in fuel switching.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
EPA must conduct an analysis of the capacity of Florida's natural gas pipelines to accommodate the increased requirement in natural gas consumption needed to meet EPA's assumptions by 2012. EPA must also perform reliability analysis as to Florida's unique situation as a peninsula regarding FMEA members' ability to meet reliability requirements in the future. And EPA's analysis must consider the parasitic load from new control equipment, such as FGD and SCR systems.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
Response:
The commenter appears to assume that dual-fueled units would be unable to consume oil if their initial allowance allocations are calculated on the basis of natural gas consumption instead.  This assumption ignores the ability of owners and operators to determine their cost-effective EGU operations, including related emissions, and acquire the requisite number of allowances accordingly under the Transport Rule's market-based air quality-assured trading programs.  In addition, this assumption is flawed because as explained in the Allowance Allocation Final Rule TSD, the economic determination of unit dispatch (including limitations on the availability of certain fuels at certain times) will always reflect the cost of emitting under the programs (i.e., the market price of an allowance) whether or not an allowance for that emission was originally allocated to the unit in question.  In this instance, a dual-fuel unit firing with oil would still dispatch if the cost of its generation, including the value of the allowances to cover emissions from such generation, is among the least-cost method of meeting demand and maintaining the viability of the grid at that time, whether or not that unit had been allocated the allowances in question in the first place.  Notwithstanding this important point, the final Transport Rule's allocations to existing units under the FIPs are based on historic data that would reflect emissions from the balance of oil and natural gas consumed by the units cited by the commenter.
Organization: Fond du Lac Reservation
Comment:
Fond du Lac Reservation
Need for Tribal Set-Aside
Aside from the above, the Transport Rule fails to provide Indian tribes with an opportunity to become part of the EPA's proposed trading scenarios. As drafted, the Rule provides allowance allocations solely to states and the District of Columbia. Under the Tribal Authority Rule, however, tribes may adopt whole or parts of air programs based on 'reasonable severability' without being subject to deadlines or other requirements imposed upon states and other jurisdictions . This is something that the Agency acknowledged in the former Clean Air Interstate Rule ('CAIR') in which it went to great lengths to address the unique circumstances of Indian tribes and the need to accommodate future electrical generating units ('EGUs') that should locate on tribal lands. 8  Unfortunately, the EPA chose to ignore this earlier assessment of tribal issues without providing a valid reason for doing so. The Band there .fore recommends that the Agency revisit its earlier analysis under the CAIR concerning tribes and establish a mechanism which allows such tribes to enter into any trading program adopted under the Rule, specifically providing EGUs locating on tribal lands with an appropriate portion of allowances. [EPA-HQ-OAR-2009-0491-3707, pp.4-5]
In addition, the EPA should provide for the inclusion of a tribal set-aside under the Transport Rule that is based on factors other than EGUs located on state lands. As reference, the Agency only needs to look to an effort in the Western U.S. which provided for a similar set-aside that received support from a wide range of stakeholders. [EPA-HQ-OAR-2009-0491-3707, p.5]
The Western Regional Air Partnership ('WRAP'), a partnership between Indian tribes, states and federal agencies (including the EPA) and with participation from such entities as environmental organizations and industry, advocated for a tribal set-aside during the late 1990s that was eventually adopted as part of the Annex to the Regional Haze Rule ('RHR'). The Annex established declining SO2 emission milestones for major sources. If the milestones were exceeded, then a cap-and-trade program would be initiated to ensure continued SO2 reductions. As part of the Annex, an annual SO2 tribal set-aside of 20,000 tons was made available to tribes within a nine-state region, regardless if such tribes had major industrial sources emitting SO2. This set-aside was to be distributed as determined by the region's tribes (e.g., for future industrial sources, other economic development purposes, tribal scholarships, etc.). This annual tribal set-aside also grew out multiple discussions among the WRAP's partners and participants where issues of equity and economic development kept coming up during conversations with respect to the tribes that had hardly contributed to visibility impairment in the West but whose environment and health had been adversely affected by neighboring jurisdictions with sources emitting significant amounts of SO2. At that time, neither the WRAP partners or participants had sufficient information about future EGUs in Indian country but they felt it imperative to address equity issues properly before and not after the Annex was implemented. [EPA-HQ-OAR-2009-0491-3707, p.5]
The Band therefore recommends that the EPA include a tribal set-aside as part of any trading program adopted in accordance with the Transport Rule. A determination about the appropriate size for such a set-aside and the means for its allocation requires the Agency to consult with tribes. [EPA-HQ-OAR-2009-0491-3707, pp.5-6]

8. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone ('Clean Air Interstate Rule'); Revisions to Acid Rain Program; Revisions to the NOx SIP Call; Final Rule, 70 Fed. Reg. 25162, 25167 (May 12, 2005) (to be codified at 40 CFR Parts 51, 72, 73, 74, 77, 78 and 96) ('[I]n the event of any future planned construction of EGUs on Tribal lands within the CAIR region, EPA intends to work with the relevant Tribal government to regulate the EGU through either a Tribal implementation plan ('TIP') or a Federal implementation plan ('FIP'). We anticipate that at a minimum, a proposed EGU on a reservation within a State participating in the CAIR cap and trade program would need to be made subject to the cap and trade program. In the case of a new EGU on a reservation in a CAIR-affected State which chose not to participate in the cap and trade program, the new EGU might also be required, through a TIP or FIP, to participate in the program. This would depend on the potential for emissions shifting and other specific circumstances (e.g., whether the EGU would service the electric grid of States involved in the cap and trade program.) Again, EPA will work with the relevant Tribal government to determine the appropriate application of the CAIR). [EPA-HQ-OAR-2009-0491-3707, p.4]
Response:
As described in Preamble Section VII.D., under the final Transport Rule 0.1% of the state budget will be set aside for the Indian country new unit set-aside
Organization: Golden Spread Electric Cooperative
Comment:
Golden Spread Electric Cooperative
I. Database corrections: Comments are directed towards the following ORIS codes and associated electric generating units (EGUs):
55065  -  Mustang Station GEN1
55065  -  Mustang Station GEN2
55065  -  Mustang Station GEN3
56326  -  Mustang Station Unit 4GEN1
56326  -  Mustang Station Unit 4 GEN2
From the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airquality/transport/tech.html), the following documents require revision in order for the EPA to accurately calculate, based on the current methodology set forth by the proposed Transport Rule, the appropriate number of NOx allocations the aforementioned EGUs should be given:
A. From the Excel spreadsheet titled, "Budgets and Allocations  -  Detailed Unit-Level Data," the following corrections are required:
Under the Worksheet titled, "Unit Characteristics,"
The capacity (MW) rating for Mustang Station Unit 4 GEN1 and GEN2 in rows 9203 and 9204 respectively should both read 152 in cells F9203 and F9204 respectively. The spreadsheet inaccurately reflects capacity ratings of 145 MW for Mustang Station Unit 4 GEN1 and 0.5 MW for Mustang Station Unit 4 GEN2. This precludes GEN 2 from receiving any NOx allocations, unfairly increasing the operating costs of the unit. In addition, the designation for "Mustang Station Unit 4" GEN1 and GEN2 should be "Mustang Station Unit 4 & 5" GEN1 and GEN2, as GEN1 is Mustang Station Unit 4 and GEN2 is Mustang Station Unit 5.
Cell N9203 inaccurately reflects that an SCR is installed on Mustang Station Unit 4 GEN1. This potentially precludes Mustang Station Unit 4 GEN1 from receiving the appropriate amount of NOx allocations under the proposed Transport Rule. Cell N9203 should not have an "X" indicating an installed SCR.
[EPA-HQ-OAR-2009-0491-2808.1 p.3]
Cell S9203 inaccurately reflects the intentions of our company(ies) to install an SCR on Mustang Station Unit 4 GEN1. Cell S9203 should not have an "X" marking the intention to have an SCR "existing or committed by 2012."
Cell W9202 should not have an "X" indicating that Mustang Station GEN3 is a "Covered Unit (Fossil >25 MW)." Mustang Station GEN3 is a steam turbine with no combustion source. This is also incorrectly reflected in the "ParsedFile[series]" Excel spreadsheets.
Cell W9204 should have an "X" indicating that Mustang Station Unit 4 GEN2 is a "Covered Unit (Fossil >25 MW)" (see 1. i. above).
Under the Worksheet titled, "Reported Data,"
The entries for rows 9200 and 9202, for Mustang Station GEN1 and Mustang Station GEN3 inaccurately reflect the characteristics of Mustang Station GEN1 and Mustang Station GEN3 (see 1. iv. above). All data should be added together and attributed to Mustang Station GEN1 based on data reported to EPA (e.g. the "Heat Input Q1  -  2008" for Mustang Station GEN1 in cell F9200 should read "2,583,932"). While this correction may not immediately affect the number of NOx allocations received by Mustang Station GEN1-3, it should be corrected in the database to prevent future errors as Mustang Station GEN3 is a steam turbine with no combustion source and not a natural gas fired turbine.
Under the Worksheet titled, "Allocations & Rate Limits,"
The same problem as 2. i. above exists and should be corrected for Mustang Station GEN1 and GEN3.
The "Heat Input assumed in Ozone Season NOx Allocation" data in cell R9204 is inaccurate and should read "882,252."
[EPA-HQ-OAR-2009-0491-2808.1 p.3]
The "Ozone Season NOx Rate[s]" in column V are inaccurate and should be changed as follows:
Cell V9200 should read "0.035."
Cell V9201 should read "0.035."
Cell V9203 should read "0.030."
Cell V9204 should read "0.045."
Using the corrected values from 3. i-iii. above, the Ozone Season NOx Allocations in column M should be changed to read 97% of the calculated value (3% reserved for new units per EPA proposed rule), rounded up to the nearest ton, as follows:
Cell M9200 should read "86."
Cell M9201 should read "84."
Cell M9203 should read "15."
Cell M9204 should read "20."
[EPA-HQ-OAR-2009-0491-2808.1 p.4]
Response:
Thank you for your comment.Organization: Institute of Clean Air Companies (ICAC)
Comment:
Institute of Clean Air Companies (ICAC)
Another benefit of maximizing flexibility for sources via EPA's preferred remedy is that sources need not have control equipment installed and operational by January 1, 2014, as explained below, especially for the Group 1 SO2 states. Sources will have the flexibility to go to the intrastate and/or interstate allowance markets to acquire the emission allowances they need for budget reconciliation. [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
Response:
Thank you for your comment.Organization: JEA
Comment:
JEA
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking and that allowance banking as an element of EPA's program was in no way undermined by the court's decision in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2713.1, p.5]
Response:
Thank you for your comment. Banking of allowances is allowed under the final Transport Rule.
Organization: Kansas City Power and Light Company (KCP&L)
Comment:
Kansas City Power and Light Company (KCP&L)
7. Prohibiting SO2 allowance trading between Group 1 and Group 2 states unfairly penalizes utilities with sources located in the same air shed, but on opposite sides of state boundaries. EPA should consider allowing trading between Group 1 and Group 2 states, or at a minimum, allow intra-utility trading between units in Group 1 and Group 2 states. [EPA-HQ-OAR-2009-0491-2709.1, p.4]
Response:
Preamble Section VI.D.2. explains EPA's rationale for and responds to comments on not allowing sources in Group 1 states to use Group 2 SO2 allowances for compliance, and likewise not to allow sources in Group 2 states to use Group 1 SO2 allowances for compliance at any time.
Organization: Lafayette Utilities System
Comment:
Lafayette Utilities System
EPA indicated that each state's budget comprises the emissions that EPA estimates remain after the state has made the reductions required to eliminate its significant contribution to nonattainment and interference with maintenance of the relevant NAAQS in other states in an average year. Under either the proposed State Budgets/Limited Trading remedy or the State Budgets/Intrastate Trading alternative remedy, each state's budget is allocated to sources within that state and EPA determines how much each source can emit without trading allowances. As support documentation to the proposed Transport Rule/FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUS. Under the Direct Control alternative, EPA projects that a state will be able to meet its good neighbor obligations each regulated EGU meeting the direct control emissions rates proposed. [EPA-HQ-OAR-2009-0491-2983.1,p.8]
LUS Objects to Use of the IPM to Make Unit Level Allocations
LUS is concerned with the NOx allocations provided to its units. An economic analysis performed for the Louisiana Public Service Commission projects that there will be an annual economic impact of $345,149 more than the cost incurred by LUS under CAIR for LUS to acquire annual NOx allowances. There will be additional cost to acquire ozone season NOx reductions. This assumes $1,200 per ton of NOx and is based upon the difference between allocations under the proposed Transport Rule/FIP and actual emissions from 2006. The projected annual average impact to LUS ratepayers would be $7.40 each. (Again, this estimate does not include the cost for ozone season NOx allowance acquisition.) This estimate would be accurate only if LUS is actually able to purchase NOx allocations from other Louisiana EGUs. LUS questions why the citizens of Lafayette should have to pay for allowances from utilities elsewhere in Louisiana. EP A does not appear to have any rational basis for these allocations. [EPA-HQ-OAR-2009-0491-2983.1,p.8]
Response:
Thank you for your comment.Organization: Large Public Power Council (LPPC)
Comment:
Large Public Power Council (LPPC)
However, LPPC also recognizes that the D.C. Circuit's decision in North Carolina placed legal constraints on EPA's ability to establish a fully fledged regional emissions trading system under Section 110 of the CAA. The most significant of these constraints is the court's holding that Section 110 requires each individual state to reduce its own significant contribution to nonattainment (and interference with maintenance) in downwind states. 38 This interpretation necessarily restricts the ability of states to "shift" emissions to other states on a regional basis through the trading of allowances  -  despite the gains in efficiency that might result from so doing. [EPA-HQ-OAR-2009-0491-2667.1, p.10]
B. Variability Limits Should Not Apply to Transport Rule Allowances That Were Banked Within the Same State in Which They are Submitted for Compliance
LPPC also objects to EPA's proposal that variability limits restrict not just the use of allowances that have been procured through interstate trading, but also banked allowances that are used by EGUs within the same state where the banked allowances were allocated. As noted in the preamble to the Transport Rule, 45 banking is a critical efficiency-enhancing feature of cap-and-trade programs that allows for cost-effective "shifting" of emissions from earlier periods of time to later periods when emissions abatement may be more costly. In addition, banking yields environmental benefits by encouraging sources to reduce emissions early, in excess of what is required by current levels of the emissions cap, in order to accumulate allowances for future use. The preamble to the Transport Rule explicitly touts the advantages of banking in support of EPA's proposed policy design, noting that "the banking provisions of the State Budgets/Limited Trading approach would provide incentives to reduce emissions as quickly and early as possible." 46 [EPA-HQ-OAR-2009-0491-2667.1, pp.13-14]
EPA's proposal, however, would needlessly limit the extent to which EGUs can realize those benefits. EPA's proposed combination of state emission budgets and variability limits is primarily intended to ensure that sources "within each State" reduce their significant contributions or interference with maintenance in downwind areas, as required by the D.C. Circuit in North Carolina. Unlimited use of banked allowances is consistent with the D.C. Circuit's holding in that case, because a source that achieves early emission reductions and banks its allowances for future use still eliminates its contribution to downwind air quality problems  -  albeit on a schedule different than is contemplated by the emissions cap. So long as they are not traded to EGUs in a different state, banked allowances do not result in the geographic displacement of emissions from one state to another, which was the D.C. Circuit's principal concern in North Carolina. [EPA-HQ-OAR-2009-0491-2667.1, p.14]
Because the use of banked allowances does not present the legal difficulties that unrestricted interstate trading was found to create in North Carolina, EPA is wrong to propose that the use of banked allowances be subject to the variability limits in the same manner as allowances traded interstate. Thus, LPPC recommends that usage of banked allowances be disregarded both for purposes of assessing whether the assurance provisions are triggered, and for determining whether a particular EGU owner has exceeded its share of the state budget plus the variability limit. This recommended exemption for banked allowances would, of course, only apply to Transport Rule allowances that are held within the same state in which they are allocated. [EPA-HQ-OAR-2009-0491-2667.1, p.14]
V. COMMENTS ON ALLOWANCE ALLOCATION METHODS
A. If EPA Rejects LPPC's Request for a Deferred Compliance Deadline, States Should Be Allowed to Elect the Allowance Allocation Methodology That Would Be Included In Individual FIPs
If EPA rejects LPPC's request for a one to two year deferral in the Transport Rule compliance deadlines, and thereby makes it impossible for states to revise their SIPs in time to avoid the imposition of a FIP, we request that EPA craft FIPs that reflect the preferences of individual states regarding the allocation of allowances to EGUs. The proposed Transport Rule would allocate NOx and SO2 allowances to existing EGUs on the basis of either their share of 2009 emissions within each state, or their share of projected 2012 base case emissions and 2014 emissions budgets as estimated by EPA. This emissions-based allocation method ensures that EGUs with the greatest demand for allowances (those with the highest NOx and SO2 emissions) receive relatively more allowances. On the other hand, this method also disadvantages EGUs that have made significant investments in conversion to cleaner fuels and installations of pollution control equipment. We believe states should have the primary role in deciding such sensitive issues of equity. In addition, we believe states are generally best informed as to the needs and circumstances of individual EGUs within their jurisdiction, and are thus in a superior position to make allowance allocations. [EPA-HQ-OAR-2009-0491-2667.1, p.17]
Thus, in the event that the Transport Rule deadlines are not changed, EPA should at least provide an informal mechanism by which states could submit their desired allowance allocation methodologies to EPA for inclusion in the Transport Rule FIPs. This mechanism would be akin to the process by which EPA has recently requested that states recommend a "reasonable deadline" for submitting revised SIPs addressing authority to issue PSD permits that include greenhouse gas limitations. 53  Such informal submissions would allow states to have voice in the allowance allocation process even if they are not able to revise their SIPs before the Transport Rule takes effect. [EPA-HQ-OAR-2009-0491-2667.1, p.17]
B. LPPC Supports the Proposed Set-Aside for New EGUs and Limited Allocations for Retired EGUs
LPPC supports EPA's proposal to reserve 3% of each state's annual emissions budget for distribution to new units. We agree this amount should be adequate to meet demand from new EGUs. Moreover, a specific set-aside for new EGUs provides existing EGUs with much-needed certainty as to the minimum quantity of allowances they would be entitled to. [EPA-HQ-OAR-2009-0491-2667.1, pp.17-18]
In addition, LPPC supports EPA's proposal to continue allocating allowances to retired EGUs for a total period of seven years after those EGUs cease operations. Retirement of aging EGUs is likely to be the most efficient and environmentally effective pollution control strategy in at least some cases. The proposed continuation of allowance allocations to retired EGUs will avoid discouraging utilities from removing units from service where it is appropriate to do so, and will smooth the path for retirements by helping mitigate the substantial costs of decommissioning, demolition and site remediation. [EPA-HQ-OAR-2009-0491-2667.1, p.18]
Response:
Thank you for your comment.Organization: Luminant
Comment:
Luminant
:: Luminant supports EPA's decisions to provide some regulatory certainty by allocating allowances permanently and to permit allowance banking beginning in 2012, to allow at least some degree of interstate trading and to not include allowance auctions in its preferred limited interstate trading option. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
III. Luminant Supports Other Aspects of the CATR
Luminant supports EPA's decision to allocate permanent allowances and to provide for banking of allowances starting in 2012. Banking encourages sources owners to make early emission reductions. Luminant also supports the use of interstate trading in EPA's preferred regulatory approach. [EPA-HQ-OAR-2009-0491-2729.1, pp.5-6]
In addition, Luminant agrees with EPA's decision not to include any allowance auctioning under its preferred limited trading option. Allowance allocation provides greater regulatory certainty and flexibility in implementing reductions. [EPA-HQ-OAR-2009-0491-2729.1, p.6]
Response:
Thank you for your comment.Organization: Massachusetts Department of Environmental Protection
Comment:
Massachusetts Department of Environmental Protection
Massachusetts has included non-EGUs and smaller EGUs in both its NOx SIP Call (310 CMR 7.28) and its CAIR ozone season NOx control programs (310 CMR 7.32). MassDEP's existing CAIR NOx Allowance Trading Program applies to units that burn more than 50% fossil fuel and have a maximum heat input capacity of250 million British thermal units (MMBtu) or more, or serve a generator with a nameplate capacity of 15 MW or more. Units are included in the NOx Allowance Trading Program whether or not they produce electricity for sale. MassDEP recommends that EPA apply a similar applicability standard in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2787.2]
EPA requested comment on the proposed approach for allocating allowances to non-operating units, including suggestions for simplifying allocations by not allocating at all to non-operating units, and on the question of maintaining perpetual allocations to non-operating units similar to the treatment of such units in the Title IV Acid Rain Program of the Clean Air Act.
MassDEP strongly objects to the proposal that non-operating units continue to receive allocations until the seventh year after the first year of non-operation. We urge EPA to not allocate any allowances in Transport Rule control programs to existing non-operating units to avoid the repeating perpetual allocations to non-operating units that occurred with the Title IV Acid Rain Program.
MassDEP urges that for all Transport Rule control programs, allowances allocated to Transport Rule eligible units not operating for three consecutive years be reallocated to the new unit set aside for the state where the unit is located beginning the next year (i.e., the fourth year), rather than the seventh year of non-operation. This will encourage operators to incorporate decisions about retirement or repowering units earlier into their compliance plamling and make additional allowances available to cleaner and presumably more efficient new electric generation resources.
We disagree with the contention that continuing to allocate allowances during the initial three consecutive years of non-operations plus another three year period will 'reduce the incentive for owners to keep units operating simply to avoid losing the allowance allocation for those units.',23 While allowance allocations are a factor in compliance planning and dispatch bidding, facilities report that fuel, operation and maintenance costs largely determine whether to bid a unit into the market or self-schedule operation for other purposes.