EPA should consider an output-based methodology or a BTU-based methodology that does not penalize natural gas and other less polluting sources of electricity. A number of states have adopted output-based allocation methods, which allocate emission allowances based on megawatts produced by power plants. This could allow states with large amounts of generation to retain significant generation, while rewarding the most efficient units. As an alternative, EPA could continue with the BTU-based allocation method it originally proposed in CAIR, without the natural gas-harming 'fuel factors' adjustment that the D.C. Circuit rejected. 14 This could allow states and utilities that combust significant quantity of BTUs to continue to do so, without penalizing a unit that has installed 'back end' emission controls. Natural gas combined cycle power plants can provide low emitting, high efficiency generation, to help meet the Clean Air Act's important air quality goals. [EPA-HQ-OAR-2009-0491-2759.1, p.5]
c. By subsidizing coal with over-allocations, EPA is failing to achieve cost-effective emission reductions that can be achieved through the increased use of natural gas.
The choice of emission allocations has real-world impacts: by subsidizing coal-fired generators with overgenerous allocations, EPA is failing to achieve cost-effective emission reductions. That would burden consumers and delay needed pollution resolutions. Numerous facts make this point clear, including the following: [EPA-HQ-OAR-2009-0491-2759.1, p.5]
Overgenerous allocations to coal-fired power plants in upwind states are subsidies that keep marginally economic, high-emitting plants operating, inhibiting emission reductions from cleaner sources of generation. In particular, the oldest and least efficient coal-burning plants may be kept operational by this subsidy. Furthermore, this subsidy may allow old coal units to escape emission controls that would be otherwise required. This subsidy for coal plants should be eliminated through a better allocation method. 15 [EPA-HQ-OAR-2009-0491-2759.1, pp.5-6]
High-emitting upwind generation makes it more difficult to develop clean downwind generation. As an example of increased costs for downwind generators, the developer of a natural gas power plant may be required to acquire expensive NOx 'offsets,' a requirement under the Clean Air Act in states that fail to attain compliance with air quality standards, which the developer wouldn't otherwise be required to obtain but for the pollution from upwind states causing the downwind state to violate the air quality standard. [EPA-HQ-OAR-2009-0491-2759.1, p.6]
CAIR's emission-based allocation has real-world impacts, and results in increased pollution from coal-fired power plants. For instance, the EPA's Regulatory Impact Analysis for CATR shows that under CATR coal generation actually increase from 2008 levels, and natural gas generation decreases. The Regulatory Impact Analysis notes that both "the base case and all three remedies show shifts away from oil and natural gas generation and toward increased coal generation between 2012 and 2014." This is a perverse result from an air quality standpoint that shows the weakness of CAIR as proposed: high-emitting coal generation increases, while clean-burning natural gas generation faces disincentives and decreases. [EPA-HQ-OAR-2009-0491-2759.1, p.6]
3. The new unit set-aside should not disadvantage to-he-constructed natural gas units.
EPA proposes new unit set asides equal to 3% of each state's budget. The size of each new unit set aside is based on 'a comparison of projected emissions from new units to projected emissions from existing units for all covered states.' If requests by new units exceed supply in a given year, new units would only receive their 'proportionate share of the new unit set-aside." Therefore, if new natural gas capacity is developed with allowance needs that exceed the set-aside, these new units may be 'short' allowances while incumbent, higher-emitting coal plants receive overgenerous allocations due to the emission-based allocation method discussed above. Moreover, a single new coal plant may consume an inordinate share of allowances from a new-source set-aside, compared to lower-emitting natural gas units. EPA should assess whether the design of the new unit set aside is sufficient for projected new types of generation, in particular projected substantial amounts of low-emitting gas-fired generation. EPA could also consider the auctioning of some portion of allowances, which could allow new generators (or natural gas units that increase their generation above baseline capacity factors) to compete with incumbent coal generation on a level playing field. [EPA-HQ-OAR-2009-0491-2759.1, p.8]
EPA should also consider provisions, either at the federal or state level, that would allow a portion of allowances that are no longer needed by non-operating units to specifically incentivize cost-effective fuel-switching to lower emitting forms of generation. These types of 'bridge fuel credit' programs have been proposed for inclusion in federal cap-and-trade legislation for greenhouse gases. [EPA-HQ-OAR-2009-0491-2759.1, p.8]
Furthermore, EPA should avoid making its allocations permanent (as it has proposed), but rather update them as necessary to reflect changes in generation sources. [EPA-HQ-OAR-2009-0491-2759.1, p.9]
14. EPA specifically requested comment on a heat-input (Le., BTU) based approach as part of the Proposed Rule. 75 FR 45311. [EPA-HQ-OAR-2009-0491-2759.1, p.5]
15. Consider the case of two utility companies that each has four units of the same vintage and megawatt capacity: one modern, 500-megawatt natural gas combined cycle unit; two large 500-megawatt coal units built in the 1970s; and one smaller coal unit built in the 1950s. Generator 1 ('Cleaner Generator') recently installed scrubbers on its two large coal units and increased its customer rates to pay for installation. Generator 2 ('Dirtier Generator') has not installed scrubbers on any of its units. Under CATR, Dirtier Generator would receive more allowances for failing to reduce emissions, and could use these allowances to offset the cost of installing scrubbers. Cleaner Generator may have to buy allowances from Dirtier Generator to cover its shortfall in allowances, so that Cleaner Generator directly subsidizes Dirtier Generator. A similar situation would occur if Cleaner Generator recently retired a coal unit and replaced it with a low-emitting NGCC unit-Cleaner Generator would receive no emission allowances to offset the cost of this conversion, while Dirtier Generator would receive extra allowances based on its high-emitting coal generation. Finally, Cleaner Generator, short allowances, may be forced to shut down its small coal unit while Dirtier Generator, with surplus allowances, could keep its dirtiest unit running without emission controls. Worse still, Cleaner Generator may then need to buy power from Dirtier Generator, increasing the demand for the uncontrolled, oldest, least-efficient, highest-emitting plant in Dirtier Generator's fleet. [EPA-HQ-OAR-2009-0491-2759.1, p.6]
American Electric Power
AEP has serious concerns with the bottom-up approach used by EPA in apportioning reductions to states and specific units as this requires that both the data and modeling assumptions be highly accurate to ensure an optimal outcome. However, in the case of this rulemaking, the data and assumptions are not representative of the actual economic and operating conditions of the electric generating fleet. Employing a methodology which specifies budgets and allocates allowances on the basis of speculative modeled reductions will lead to costs much higher and disproportionate than optimally needed. [EPA-HQ-OAR-2009-0491-2665.1, p.11] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.7]
The modeling support for the Proposed Transport Rule does not take into account the reductions that are occurring under the current CAIR program in the absence of this rulemaking. CAIR continues to be in effect until further regulations are promulgated and utilities are currently factoring this into their planning process. Additionally, the IPM modeling did not contemplate the myriad of other regulations (e.g. coal combustion residuals, hazardous air pollutants, cooling water intake) that EPA is currently developing that affect the same electric generating units subject to the Proposed Transport Rule. Planning decisions do not occur in isolation within the electric utility sector, particularly those relating to retirement and retrofit decisions. Given EPA's schedule for rule promulgation, it is arbitrary and irrational to base a rule and allocation system on modeled reductions that do not take into account the effects of the full suite of related new regulations which are currently proposed or publicly announced and soon to be proposed by EPA. AEP and all other utilities must take into account potential outcomes for new regulation in the real world planning process and EPA's modeling efforts should be revised to take into account likely regulatory outcomes as well. As a result of EPA's artificial and myopic IPM modeling approach, combined with data and assumption errors, the IPM modeling relied upon by EPA dramatically underestimates the amount of coal unit retirements due to the proposed rule. Accompanying these coal units retirements will be lost jobs, lost tax revenue and higher energy prices, all presenting major obstacles to an economic recovery. These enormous indirect costs of the Proposed Transport Rule have been arbitrarily ignored by EPA in formulating its proposal. [EPA-HQ-OAR-2009-0491-2665.1, pp.11-12
Additionally, the complexity of the model makes it impossible to review the accuracy of all inputs and outputs of the model with the level of scrutiny required given the enormous financial implications of this model. This frustrates the ability to meaningfully comment on the true basis and purpose of EPA's proposal. Furthermore, EPA has indicated its intention to continue changing the NEEDS database and IPM modeling inputs and outputs without adequate notice and opportunity to comment on those ongoing changes. Therefore, AEP requests any interim model updates which include the incorporation of data corrections or new information be released publicly upon completion to ensure they can be reviewed for accuracy. Additionally, AEP requests that a full suite of IPM results be released on an individual unit basis and not just through the parsed file and grouped model outputs, with an adequate opportunity for review and comment. [EPA-HQ-OAR-2009-0491-2665.1, p.12] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.7]
Budget Allocations aud Equity
The allocations as detailed in the proposed remedy are based on the lower of historical or forecast emission levels in 2012 and forecast emissions in 2014. These allocations take into account modeled control equipment installations, dispatch changes, and fuel switching. This system sets a new precedent for a cap-and-trade program by allocating based on what a computer model calculates to be economic. This takes the modeling logic one step too far, given the considerable uncertainty surrounding the economics of utility system future planning decisions. While modeling could be used to specify state or regional permissible emissions, the model outcomes should not be used to drive allocations at the unit level. Rather, unit-level allocations should: I) be determined by the host states through a state implementation plan; and 2) be based on historical emissions. Taking historical emissions into account is much more equitable in that it does not penalize companies who have invested heavily in controls in advance of future regulations. [EPA-HQ-OAR-2009-0491-2665.1, p.15]
AEP is disproportionately affected by the proposed budget allocation methodology as a result of both projected controls and incorrect data. As an example, initial EPA modeling of the interstate trading option indicates that 5.7 gigawatts electric generating capacity within the AEP eastern fleet would install FGD systems as a result of the rule, or 40% of the projected FGD installations from the entire Proposed Transport Rule program. In other words, 40% of the burden of reductions (as dictated by commensurately decreased allocations) for the program has been placed on AEP and its customers even though it is responsible for well less than 10% of covered source emissions, and virtually zero of the contribution to predicted pockets of nonattaimnent remaining after implementation of the current CArR program and other existing regulatory requirements. [EPA-HQ-OAR-2009-0491-2665.1, pp.15-16]
AEP is also concerned with the use of the lower of historical versus modeled emissions and the discrepancies this has caused. The historical data used for 2012 SO2 budget development are from the years 2008-2009. Late 2008 and early 2009 happen to coincide with the longest and deepest economic recession since World War II, and represent one of the lowest periods in recent history of utility power plant utilization. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
Additionally, emissions during this period were exceptionally low as high cost uncontrolled units did not run. Thus, using the portions of 2008 and 2009 as a heat input basis for state and unit level budgets is highly punitive and arbitrary. Additionally, this budgeting method is punitive to units which had an outage to install controls (as AEP was required to do at a number of its units under its NSR Consent Decree with EPA) which reduced heat input relative to other periods. Furthermore, subsequent corrections to emission rates based on projected control installations is also inaccurate because installations dates are rounded to the nearest years and thus don't consider partial years of operation, resulting in an additional haircut. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
Given the aforementioned issues, a more representative historical time perspective should be used to set 2012 S02 budgets. We would recommend a three year average from 2006- 2008 to capture more typical plant operation. Furthermore, any corrections to unit emission rates for controls should: a) take into account more realistic performance expectations (see NEEDS FGD Removal Assumptions comments); b) adjust for higher sulfur coal use with FGD installations; and c) take into account only partial year operation of control equipment. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
American Public Power Association (APPA)
In developing the Proposed Transport Rule, EPA used photochemical source apportionment modeling to identify the impact of emissions from specific upwind states on downwind areas projected to be in nonattainment or to have maintenance problems in 2012. 75 Fed. Reg. at 45253/1. Then, EPA determined each state's significant contribution to nonattainment and interference with maintenance based on the emissions that EPA projected could be eliminated from that state for a specific cost (in dollars per ton of reduced emissions), in conjunction with an analysis of air quality benefits at various cost levels, and set state budgets accordingly. 75 Fed. Reg. at 45271/1-2. Thus, although APPA disagrees with many aspects of the data and methodology that EPA used in this analysis, EPA`s methodology does, as a general matter, attempt to address the EPA-projected contribution to nonattainment and interference with maintenance in downwind states from emissions from particular upwind states. At least in broad terms, the PTR`s focus on state-specific data should align with the court`s characterization of states` section 110(a)(2)(D)(i)(I) duties. [EPA-HQ-OAR-2009-0491-2812.1, pp.9-10]
APPA applauds the U.S. EPA`s proposal for the decision not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule`s emission reduction requirements. If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that APPA (and UARG) does not support, EPA should remove from that option the proposed provisions for allowance auctions. It is entirely possible to accomplish the objectives of those proposed auctions through distribution of allowances free of charge. [EPA-HQ-OAR-2009-0491-2812.1, p.13]
As explained in section VI below, government auctioning of allowances is contrary to the principle that regulated sources are not subject to any obligation to emit below their allowance allocation levels established by the program. Revenues from the allowance auctions that EPA describes in the Intrastate Trading Remedy Option would be deposited into the U.S. Treasury. 75 Fed. Reg. at 45327/2. The effect of such auctions, in which proceeds accrue to the government, is to force affected sources to pay not only for emissions that exceed their emission allocation levels but also for the right to emit below those levels. There is no legal basis for charging sources for the right to emit tons of emissions that are within their allowance allocation levels -- indeed, the very word "allowance" denotes that a source is allowed to emit within the limits of its allowance allocations -- and providing revenue to the U. S. Treasury is not a legitimate purpose of section 110(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-2812.1, pp.13-14]
ARIPPA
These projections directly translate into disparate and unsupportable allowance allocation proposals under the FIP. EPA proposes to allocate unit-specific allowances to ARIPPA facilities (and apparently other small independent power production units) at a substantially reduced rate, in significant part on the basis that EPA projects that such sources will operate at reduced capacity compared to current levels. EPA conversely proposes to provide increased allowance allocations to certain larger traditional utility units, by projecting that such sources will increase their relative operating rates. [EPA-HQ-OAR-2009-0491-2794.1, p.10]
Significantly contrary to EPA's approach in the context of all prior Title I emission transport programs, EPA does not propose through the Proposed Rule to establish allowance allocations based upon heat input, but rather projected emission rates. EPA's projected emission rates rely upon both EPA's projections of electricity generation rate and EPA's assumed future emission rates for the relevant pollutant. For the reasons discussed above, the component of the projection relying upon rates of generation is inappropriately skewed based upon consideration of incomplete and incorrect factors in reasonably estimating relative rates of future electricity generation. EPA's analysis is similarly flawed with respect to the other component of its projection  -  emission rate. Perhaps more significantly, however, relying upon this basis for projection is contrary to the mandate of the Clean Air Act, the directives of the Court in North Carolina, and inconsistent with appropriate public policy. In particular, those affected EGUs projected by EPA to emit regulated pollutants at higher rates would receive a higher relative allowance allocation under the Proposed Rule. Under other prior regulatory trading programs, consistent with the objectives of the Clean Air Act, EPA instead proposed to provide allowances based upon established heat input, and application of a consistent emission rate to that established heat input. Because of the approach utilized in this case, the ARIPPA facilities are effectively penalized relative to the proposed allowance allocation because they are relatively lower emitting sources. [EPA-HQ-OAR-2009-0491-2794.1, p.10]

Further, in proposing unit-specific allowance obligations under the Proposed Rule, EPA projects emission rates, based on EPA's analysis of "cost effective" controls for these EGUs. As more fully detailed above, EPA inaccurately predicts that the control options identified for traditional EGUs under the Proposed Rule would likewise apply to the ARIPPA facilities. Therefore, EPA appears to project that the ARIPPA facilities would achieve anticipated emission reductions assumed through the application of the specified control options. As described above, these assumptions are incorrect when applied to the operating and technological characteristics of the ARIPPA CFB sources. Therefore, the same emission rates for ARIPPA facilities would not be "cost effectively" controlled to the lower emission rates calculated by EPA based upon technologies that cannot be cost effectively applied to ARIPPA sources. In this way as well, EPA has inappropriately reduced the proposed allocation for these sources. [EPA-HQ-OAR-2009-0491-2794.1, p.11]
The combination of EPA's incorrect projections of both future rates of generation and future emission rates results in a greatly magnified discrepancy between appropriate estimation of future rates of emissions relative to those identified by EPA. In turn, these errors translate into EPA's proposed unit-specific allowance allocations, as EPA proposes to provide substantially greater allowances to larger, higher-emitting traditional coal-fired EGUs, while materially reducing the relative allowance allocations for smaller independent power production facilities, including the ARIPPA facilities. This disparity in projected rates relative to EPA's proposed unit-specific allowance allocations, is reflected in the following table depicting NOx emissions and allowance information for selective EGUs in Pennsylvania: [EPA-HQ-OAR-2009-0491-2794.1, p.11]

[Table 2 can be found on page 12 of this comment.]
The information presented in Table 2 demonstrates that the ARIPPA plants, which are inherently cleaner burning than larger traditional utility units (with NOx emission rates, on a pound per MMBtu basis, two-to-nine times lower for ARIPPA plants), would actually receive fewer allowances under the Proposed Rule (on both absolute and relative bases) than larger traditional utility units, as a result of EPA's assumptions regarding operating and emissions rates at the ARIPPA facilities in the future. Indeed, under the Proposed Rule, certain traditional utility units would only be required to reduce emission rates to levels that are higher than those already being achieved by the ARIPPA plants. [EPA-HQ-OAR-2009-0491-2794.1, pp.12-13]

For these reasons, the approach toward unit-specific allowance allocations selected by EPA through the Proposed Rule cannot be justified relative to the mandates imposed through the Clean Air Act, the direction of the Court in North Carolina, or defensible public policy. The information in Table 2 reflects that numerous larger EGUs would receive a substantially higher allowance allocation under the Proposed Rule than provided to such sources under CAIR. By contrast, the ARIPPA facilities and other smaller units receive a substantially reduced allocation relative to that established under CAIR. The bases for these relative changes and proposed distribution of allowances relate to EPA's attempts to justify provision of greater allowances to sources with higher emitting rates, rather than establishing an allowance allocation scheme that is tied to an objective rate of emissions and an established pattern of operation. The Court's directive  -  that EPA should ensure that its rulemaking more directly requires emission reductions in a manner that is linked to prevention of significant contribution to downward nonattainment  -  is clearly ignored in the circumstance in which larger emitting units with emission characteristics far more likely to cause downward impacts would be afforded the opportunity to substantially increase emissions under the Proposed Rule when compared to CAIR, while the smaller emitting units, for which EPA has not even established significant contribution to downward nonattainment, would be driven to reduced rates of emissions. [EPA-HQ-OAR-2009-0491-2794.1, p.13]

In essence, through the Proposed Rule, EPA proposes to make determinations regarding relative electric generating distribution among various sources. By proposing allowance allocations consistent with these relative electric generating rates, EPA would propose to influence this distribution of generating capacity among source types. Any such judgments regarding relative electric generating capacity among various sources is entirely inappropriate for EPA's determination, inconsistent with lawful objectives of the Proposed Rule, and clearly not consistent with statutory mandates imposed on EPA through the Clean Air Act. [EPA-HQ-OAR-2009-0491-2794.1, p.13]

The significance of EPA's approach under the Proposed Rule is substantially magnified because of EPA's proposed restrictions on allowance transfer. By severely limiting opportunities for securing allowances necessary for compliance demonstrations, EPA would restrict the ability of sources to comply with allowance obligations by more cost effectively securing greater emission reductions at other sources. These restrictions are least pronounced for companies that operate multiple emission units, at least within the same state, since the freedom to transfer allowances among such units is greatest under EPA's various approaches. By contrast, smaller facilities with single affected units are afforded no such option. Where such sources also cannot cost effectively reduce emissions at the affected source because of the unique operating, design or fuel characteristics, as in the case of the waste coal-fired CFB units, such facilities may not be afforded any compliance option under the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.13]

ARIPPA objects to the approach used by EPA for determining unit-specific allowance allocations under the proposed FIP. Allowance allocations should be consistent with previously established heat input rates, as reflected in historical data. The allocation methodology should also reflect appropriate equitable considerations, including a source's emissions characteristics, emissions control limitations, and fuel source. Consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility? this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source. Such approach would also be consistent with the objectives of the Clean Air Act and the D.C. Circuit Court's decision in North Carolina, by ensuring that the proposed program does not result in an emissions increase for any source. Significantly, the proposed allocations should not reflect EPA's judgments about shifting generation rates among source types. 6   [EPA-HQ-OAR-2009-0491-2794.1, p.14]

To the extent that EPA identifies a justifiable basis to regulate the ARIPPA facilities under the Proposed Rule, EPA's proposed basis for determining unit-specific allowance allocations to these waste coal-fired CFB units under the proposed FIP is inappropriate and inequitable. In determining the proposed allowance allocations for affected EGUs in Pennsylvania, EPA relied on several considerations, including, most notably, projected emissions. EPA derived these projections based, in part, on anticipated generating rates, which EPA calculated by focusing primarily on fuel cost. EPA's reliance on fuel cost as a primary factor in determining future generating rates for the ARIPPA sources is flawed, because (1) EPA's cost estimates for coal refuse in the Proposed Rule are incorrect, and (2) EPA fails to consider the significant additional factors which affect generating rates, such as state-specific requirements to use renewable energy sources, and contractual obligations limiting operating rate. For the ARIPPA facilities, EPA has apparently predicted a substantial decline in operating rates, which is directly inconsistent with the operating history for these plants (see Section I.B., Table 1). Moreover, operation at the rates projected by EPA would cause certain ARIPPA facilities to breach their contractual obligations pursuant to PPAs. [EPA-HQ-OAR-2009-0491-2794.1, p.20]

ARIPPA instead recommends that allowance allocations should be determined based on previously established heat input rates, as reflected in historical data reported by each source. This approach would be consistent with the objectives of the Clean Air Act, as well as the directives of the Court in North Carolina, by ensuring that the Transport Rule targets emission reductions from those sources most likely contributing significantly to downwind nonattainment, rather than lower emitting units projected by EPA (based on limited criteria) to reduce rates of generation. [EPA-HQ-OAR-2009-0491-2794.1, p.20]

Additionally, EPA's proposed approach of establishing allowance allocations based on emission rates is contrary to the approach used in the context of all prior Title I emission transport programs, which based allowance allocations on heat input, and is fundamentally inconsistent with the requirements of the Clean Air Act. EPA's proposal to allocate unit-specific allowances based on projected operating rates results in the ARIPPA facilities being allocated allowances at a substantially reduced rate, while larger traditional utility units, for whom EPA has predicted an increase in generating rates in future years, would receive increased allowance allocations. This aberrational result is not only contrary to the Court's analysis in North Carolina but flawed as a matter of public policy. [EPA-HQ-OAR-2009-0491-2794.1, p.21]

Within the Proposed Rule, EPA explains that it wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues through a SIP should they choose to do so. Indeed, EPA's stated intent is to provide states with substantial flexibility in implementing the Transport Rule. ARIPPA strongly endorses EPA's intention to ensure states substantial flexibility in implementing the requirements of the Transport Rule. Consistent with this approach, states should be allowed under the Proposed Rule to allocate allowances to affected EGUs in any manner, and on any basis, they deem appropriate to satisfy their established emission budgets. [EPA-HQ-OAR-2009-0491-2794.1, p.21]

ARIPPA also urges EPA to finalize a Transport Rule that maximizes flexibility for interstate allowance trading. EPA has previously promulgated, and continues to implement, successful emission control programs under Title I which rely on the availability of interstate trading for their effectiveness, and which have survived judicial scrutiny. Additionally, due to the marked conservatism inherent in the state emission budgets, EPA could eliminate the restrictions on interstate trading in the Proposed Rule and still meet its objectives for addressing interstate transport. [EPA-HQ-OAR-2009-0491-2794.1, p.21]

An affected source must be able to rely upon allowances secured through interstate trading as its compliance strategy, without being concerned that those allowances may lose their emission value or must be surrendered by the facility because of overall emission rates for the state. This notion becomes especially critical for facilities, like the ARIPPA plants, that would not receive an adequate allowance allocation under the Proposed Rule and, accordingly, would be forced to rely on allowance trading to secure sufficient allowances to offset their emissions. The implementation of a flexible interstate allowance trading program through the Transport Rule would be consistent with EPA's stated key guiding principles for development of the Proposed Rule, including cost effectiveness, providing incentives and flexibility to the regulated community, and ensuring a reliable power supply. [EPA-HQ-OAR-2009-0491-2794.1, p.21]

A. EPA's proposed unit-specific allowance allocations under the Proposed FIP remain inappropriate and inequitable under the NODA, as applied to the ARIPPA plants.

ARIPPA provided extensive comments on the Proposed Transport Rule in support of the position that EPA's stated basis for determining unit-specific allowance allocations under the proposed FIP is inappropriate and inequitable. In publishing the NODA, EPA reports that it devised a more refined model for projecting information relevant to the proposed allocation of unit-specific allowances under the FIP. Although the information identified through the NODA appears to represent a positive refinement in the accuracy and appropriateness of EPA's projections, for the reasons more fully detailed below, EPA's modeled projections remain substantially inaccurate and inappropriate, at least with respect to the ARIPPA facilities. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.2]

EPA proposed through the Proposed Transport Rule that each state's emission budget would be constructed from a combination of reported data and projected emissions data for the EGUs in that state. See "State Budgets, Unit Allocations, and Unit Emissions Rates", Technical Support Document ("TSD") for the Transport Rule, Dkt. ID No. EPAHQOAR20090491, EPA, Office of Air and Radiation, July 2010, at *3. In turn, each EGU's contribution to the state's budget forms the basis of its specific allowance allocation. Id. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.2]

In determining the proposed allowance allocations for affected EGUs in Pennsylvania, EPA relied on several considerations, including projected emissions. EPA attempts to project emission rates based upon its own assessment, reflective of integration between different modeled projections, of anticipated generating rates in the future. EPA's projections for future generating rates are closely linked to its assumptions concerning the future cost of electricity generation, focusing principally on fuel cost. Relative to the ARIPPA facilities, EPA's consideration of fuel cost is flawed in two important respects. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.2]

First, EPA incorrectly estimates the cost of coal refuse as a fuel, as reflected by current fuel costs incurred at the point of fuel production. For example, an evaluation of current actual fuel costs for five representative ARIPPA plants yields an average cost of $1.48/MMBtu. One of these plants reports a current actual fuel cost as low as $0.82/MMBtu. These fuel costs are somewhat inflated insofar as they include, in some cases, costs not directly attributable to the cost of fuel, including ash disposal. Nonetheless, these cost figures are still meaningfully lower than the cost estimates relied upon by EPA to project future fuel costs for coal refuse. EPA appears to have adjusted the bases for its fuel cost analyses relative to coal refuse in the context of the NODA. In fact, it appears that EPA substantially increases its projected fuel cost factor for the use of coal refuse as a fuel. This substantial increase in fuel cost (without regard to other factors used in the model) has the effect of prompting a projected decrease in utilization of EGUs firing coal refuse as a primary fuel. Therefore, at least with respect to this one factor relevant to EPA's modeled generating rates, EPA's change in fuel cost for coal refuse through the NODA would exacerbate the problems with EPA's modeled projections for future generation rates, which would translate into further inaccuracies in the proposed unit-specific allocations under the FIP. [EPA-HQ-OAR-2009-0491-3794.1_NODA,p.2]

Second, EPA's reliance on fuel cost as the primary basis for projecting future generating rates fails to adequately account for numerous other factors affecting generating rates. For example, in Pennsylvania, electricity distribution facilities and suppliers are required to supply a certain percentage of energy from Tier I or Tier II renewable energy sources, irrespective of electricity prices. Therefore, distribution of the generation of electricity will not strictly adhere to lowest cost of generation, as other operative criteria dictate distribution. Because coal refuse-generated electricity qualifies as a Tier II renewable energy source, coal refuse-fired sources will operate at a higher generating rate than cost alone would suggest. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3]

Additionally, the ARIPPA facilities are subject to contractual agreements pursuant to PPAs and other legal vehicles which dictate minimum or required energy generation and purchase rates, as between these generating facilities and electricity supply and distribution utilities. Pursuant to these agreements, subject to certain allowances for maintenance and downtime, these "coal refusefired EGUs" will operate at a certain rate and supply a certain baseload quantity of electricity to the grid, regardless of relative costs of generation. Although EPA's refined model mitigates, to some extent, the inaccurate projections of future generation rates to the extent influenced by factors other than fuel costs, the refined model does not sufficiently address these considerations and continues to result in incorrect and inequitable projected outcomes. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3]

Likely because of its failure to accurately consider the true cost of coal refuse as a fuel and account for non-fuel cost considerations, EPA apparently "predicts" a substantial decline in operating rates for virtually all the ARIPPA facilities, and then uses these predictions to determine allowance allocations for the facilities. By contrast, EPA projects that many larger traditional coal-fired EGUs will increase generating rates in the future, in some cases, substantially. In all cases, these projections are directly inconsistent with the operating history for these plants. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3]

ARRIPA recognizes that the NODA identifies the use of EPA's more refined modeling analysis, and that such refined model reduces the degree of inaccuracy in future projections. However, these refinements far from eliminate such inaccuracies. Specifically, the following tables reflect the disparity between established operating rates for a representative group of existing Pennsylvania facilities and the operating rates projected by EPA through application of its models. Table 1 provides the comparison relative to the information and projections identified by EPA through the Proposed Transport Rule. The Table clearly reveals that EPA projects a material increase in generation rates for larger, higher emitting, traditional coal-fired facilities, while correspondingly projecting material decreases in generation rates for smaller, nonconventional, coal refuse-fired CFB units. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3]

Table 2 summarizes similar information, but reflects the analysis resulting from application of EPA's refined modeling evaluation described in the NODA. A comparison of the information included within Table 1 with the information included within Table 2 reveals that the extent of the disparity between the source types is less under EPA's refined modeling. However, it is also evident that, even applying the refined model identified by EPA through the NODA, EPA continues to project future generation rates in a way that proposes to shift electricity distribution from smaller, cleaner, nonconventional, coal refusefired CFBs to larger, traditional, higheremitting coalfired sources. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3 4 for Table 1 and p.5 for Table 5.]]

Relative to the ARIPPA plants, for the reasons stated above, EPA's projected rates of generation clearly understate reasonable estimations of future operations based on consideration of all relevant factors. Indeed, in many cases, EPA's projections directly conflict with specific contractual obligations undertaken by the plants pursuant to PPAs to supply alternative energy to utility companies at a fixed price. In other words, operation at the rates projected by EPA for purposes of the Proposed Rule would cause certain ARIPPA facilities to breach their contractual obligations. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.5]

These projections directly translate into disparate and unsupportable allowance allocation proposals under the FIP. EPA proposes to allocate unitspecific allowances to ARIPPA facilities (and apparently other small independent power production units) at a substantially reduced rate, in significant part on the basis that EPA projects that such sources will operate at reduced capacity compared to current levels. EPA conversely proposes to provide increased allowance allocations to certain larger traditional utility units, by projecting that such sources will increase their relative operating rates. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.5]

Significantly, contrary to EPA's approach in the context of all prior Title I emission transport programs, EPA does not propose through the Proposed Rule to establish allowance allocations based upon heat input, but rather projected emission rates. EPA's projected emission rates rely upon both EPA's projections of electricity generation rate and EPA's assumed future emission rates for the relevant pollutant. For the reasons discussed above, the component of the projection relying upon rates of generation is inappropriately skewed based upon consideration of incomplete and incorrect factors in reasonably estimating relative rates of future electricity generation. EPA's analysis is similarly flawed with respect to the other component of its projection  -  emission rate. It does not appear from the information identified through the NODA that EPA's refined modeling analysis corrects, in any way, the flaws in its emission rate projections through the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6]

Based upon our review of EPA's database, the inaccuracies in EPA's modeled projections may result, in significant part, from EPA's incorrect information or assumptions concerning facility-specific heat rate and availability  -  factors relied heavily upon by EPA in projecting future generation rates. Individual ARIPPA facilities will provide additional site-specific comments on certain of these inaccuracies. However, it is important to note generally that EPA's approach toward heat rate reflects fundamental misconceptions in the operation of CFB units, especially with respect to the methods used to control emissions. As more thoroughly discussed by ARIPPA in the context of its comments on the Proposed Transport Rule, CFB units inject limestone directly into the combustion bed to achieve SO2 control. To the extent that additional limestone can be added to achieve any further SO2 reduction, 2 such further increase in the addition of limestone will bear upon the actual heat rates for these facilities. 3 Specifically, increased limestone injection requires additional fuel usage, thereby increasing the total heat input to the boiler without correspondingly increasing energy production. At the rates of SO2 control already achieved by these plants, significant additional limestone is required for minor further reduction in SO2 emissions? therefore, the ARIPPA facilities would experience a substantial increase in heat input per unit output in an effort to pursue compliance with the emission standards identified in the Proposed Transport Rule. This corresponds to an increased heat rate for these plants relative to that projected by EPA. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6]

The combination of EPA's incorrect projections of both future rates of generation and future emission rates results in a greatly magnified discrepancy between appropriate estimation of future rates of emissions relative to those identified by EPA. In turn, these errors translate into EPA's proposed unit-specific allowance allocations, as EPA proposes to provide substantially greater allowances to larger, higher-emitting traditional coal-fired EGUs, while materially reducing the relative allowance allocations for smaller independent power production facilities, including the ARIPPA facilities. ARIPPA's comments on the Proposed Transport Rule discuss these flaws and their bases, and ARIPPA incorporates those comments into these comments on the NODA. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6]

ARIPPA objects to the approach used by EPA for determining unitspecific allowance allocations under the proposed FIP. As addressed and supported in ARIPPA's comments on the Proposed Transport Rule, allowance allocations should be consistent with previously established heat input rates, as reflected in historical data. The allocation methodology should also reflect appropriate equitable considerations, including a source's emissions characteristics, emissions control limitations, and fuel source. Consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility? this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source. Such approach would also be consistent with the objectives of the Clean Air Act and the D.C. Circuit Court's decision in North Carolina, by ensuring that the proposed program does not result in an emissions increase for any source. Significantly, the proposed allocations should not reflect EPA's judgments about shifting generation rates among source types. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.7]

 6 For these purposes, ARIPPA distinguishes between circumstances in which a facility has shutdown and/or surrendered its air quality permits. ARIPPA acknowledges that, to the extent that a facility is no longer physically or legally capable of operating at heat input rates previously achieved and documented for such sources, providing allocations to such sources based upon historic heat input rates would inappropriately direct an emission distribution to sources that clearly cannot generate comparable emissions. Such circumstances, however, are significantly distinct from the situation, reflected in the Proposed Rule, in which EPA proposes to distribute allowances based upon EPA's projections of shifting electricity generation, where such projections are not dictated by any factual or legal requirement. [EPA-HQ-OAR-2009-0491-2794.1, p.14]
2 ARIPPA has separately commented that many factors restrict the ability of individual plants from achieving material improvements in SO2 reduction through limestone addition. In fact, it is not even possible for these plants to achieve the degree of SO2 emission controls contemplated by EPA for these sources through the Proposed Transport Rule by increasing limestone addition rates. Moreover, the increase in limestone addition has corresponding impacts on emission rates for other pollutants? for example, such change in limestone addition will likely contribute to additional NOx formation and emissions. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6]
3 With respect to NOx emission controls, as stated above, increased utilization of limestone to attempt to further reduce SO2 emission rates would contribute to increases in uncontrolled NOx emissions and increased heat input. Although increases in ammonia injection (though costly) could theoretically achieve enhanced NOx emission reduction, the permits applicable to most ARIPPA members include strict limitations on ammonia slip. Therefore, these facilities cannot materially increase ammonia injection rates while still adhering to their permit limits. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6]

Associated Electric Cooperative, Inc. (AECI)
Under the Clean Air Interstate Rule (CAIR), states developed their own methods to arrive at approvable plans largely through engaging the regulated community as stakeholders. Given more time, states could put in motion the same allocation procedures to distribute their budgets under the Transport Rule. The states are closer to the regulated facilities and are better equipped to distribute allowances, implement regulations, and issue permits.  [EPA-HQ-OAR-2009-0491-2845.1 p.3]
EPA's method of assigning unit allocations in the proposed rule is confusing at best and in many cases appears to include bad assumptions. Individual states are better equipped to assure the quality of the information and assumptions for the smaller set of units within their borders. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
There are no legal mandates to replace CAIR by a date certain, thus making the proposed 2012 CATR deadline unnecessary. Associated doubts that EPA can demonstrate measurable environmental benefits by ending Phase I of CAIR in favor of the CATR FIP. Even if demonstrable benefits exist, Associated questions whether EPA has the authority to mandate CATR by a FIP. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
EPA's presumptions on existing or projected emission rates and representative annual heat input totals are simply wrong in many cases. The methodology of picking emissions and heat input data from a potentially non-representative and narrow operating window (i.e. all or part of years 2007, 2008, and 2009) is misguided and faulty. Further, the quality of the IPM/NEEDS inventory assumptions is certain to be too weak for assigning emission allowances and it presumes too much on the generating plans of utilities. There is no way that EPA can look into a crystal ball and predict how much a unit will operate in the future. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
The proposed allocation methodology departs radically from previous air act allowance allocation without explanation. By using only the most recent operating and emissions data from periods of economic downturn, EPA's allocation methodology includes potentially non-representative unit data. Further, EPA's proposed system relies on computer modeling of future individual unit utilization and emissions controls operation or installation. In other words the rationale for the unit allocations comes from EPA's computerized virtual world containing numerous false assumptions. [EPA-HQ-OAR-2009-0491-2845.1 p.8]
The proposed system punishes, not rewards cleaner units, and penalizes rate payers buying from cleaner generating sources at necessarily higher electric rates. EPA has not explained why it has chosen this allocation methodology over more equitable and historic formulas. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
The proposal does solicit comment for alternative approaches, and in particular an approach based on heat input, p. 45311. Associated suggests the allocation methodology similar to that promulgated in CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This heat input driven system was not overturned by the court's decision in North Carolina. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
As this alternative is detailed somewhat in the proposal, state budgets would be distributed pro rata based on unit historic heat input. Several subcategories could be developed, such as coal and natural gas generation, whereby allowances are distributed based on state allowance budgets and historic heat input from each subcategory. As with the CAIR NOx allowance state option, the allowance allocations to existing units should be based on historic unit highest three of five years heat input. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
Associated advocates the Missouri model for distributing the state CAIR budget that was written into the SIP at 10 CSR 6.362 and 10 CSR 10-6.364. These CAIR NOx allocations were developed by taking the average of the highest three heat input (total annual MMBTU) of a five (consecutive) year range. Each unit was given the benefit its highest heat input, thus putting each unit on a level playing field. The unit heat input was then summed to a total state heat input pool, and a percentage of the total was calculated for each unit according to its contribution to the pool. Each unit was then allocated a pro rata share of the state budget equal to it's percentage of the state heat input pool. Using this method would result in filtering out years of lower production due to special circumstances and put each unit/facility on a more level playing field. Associated recommends using the years 2005  -  2009 for these calculations. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
Request: Should a FIP become necessary according to CAA 110, AECI requests that EPA modify the allocation methodology to the states and to individual units by averaging the three highest heat input years from the years 2005  -  2009. The allowances to the states would be  distributed as a pro-rata share of the total cap of the Transport Rule. Unit/facility allocations would be distributed as a pro-rata share of the state cap. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
Buckeye Power, Inc.
Buckeye is concerned that CATR will punish, rather than reward, electric generating facilities that have already installed emission control systems. Regardless of the methodology used to develop the allowance allocation scheme, EPA must not penalize those that have been proactive in reducing emissions. At a cost of almost $1 billion, Buckeye has installed state of the art and high performing selective catalytic reduction technology ('SCRs') on 100% of its coal-fired units, and has or will soon have installed jet bubbling reactor ('JBR') flue gas desulfurization ('FGD') equipment on 100% of its coal-fired units. At a minimum, CATR must not result in Buckeye being allocated less allowances than it needs to operate its units while employing best available control technology. We understand that a purpose of the rule is to require other utilities to commit to the same scope of an emissions control program as Buckeye has already undertaken, and we support that goal. We agree that uncontrolled coal-fired units need to reduce emissions, but Buckeye already has invested in such an emissions control program at a substantial cost to its members and their approximately 380,000 retail members/consumers in the State of Ohio. Buckeye should be rewarded, not punished, for having already installed these technologies. [EPA-HQ-OAR-2009-0491-2710.1, pp.1-2]
Whether allocations are made pursuant to a FIP or a SIP, individual unit allocations should be based on a unit's historic heat input rates, rather than emissions. Utilizing EPA's proposed approach rewards companies that have delayed installation of control technology. [EPA-HQ-OAR-2009-0491-2710.1, p.2]
Furthermore, whether using historic emissions or heat input to allocate emission allowances, a multi-year test period, rather than a single test year, is clearly more representative of a unit's operations and, therefore, a fairer allocation methodology. In anyone year, such variables as economic circumstances, weather, performance of generating equipment, and/or performance of emission control equipment, including scheduled and forced outages, may skew an allowance calculation, if it's based only on such year. On the other hand, a multi-year test period can average these variables over time. Such a risk is exacerbated for a small utility such as Buckeye with only a few electric generating units, which can not average such variables over a large number of generating units and different geographic locations, as larger utilities can. [EPA-HQ-OAR-2009-0491-2710.1, p.2]
EPA's proposed allocation methodology departs radically from previous Clean Air Act allowance schemes without explanation. EPA's proposed system relies on a single test year of historic actual emissions and on computer modeling of future individual unit utilization and emissions controls operation or installation, rather than relying on heat input and a multi-year test period as used in previous EPA emission allowance allocation proposals. It proposes a federal implementation plan rather than the use of a state implementation plan as the Clean Air Act requires. It unfairly and unreasonably requires utilities, such as Buckeye, who have or will have installed best available pollution control technology, to acquire additional emission allowances (if any will be available under CATR) or to curtail operations in order to meet emission control limitations under CATR. It unfairly and unreasonably renders worthless emission allowances that utilities, such as Buckeye, acquired under CAIR to meet the obligations and requirements of existing law. [EPA-HQ-OAR-2009-0491-2710.1, p.4]
1. Allowances should be apportioned by heat input.
The proposed system punishes, not rewards, cleaner units, by basing the allocation of emission allowances on historic actual emissions, which are necessarily lower on existing controlled units than uncontrolled units. This penalizes utilities, such as Buckeye, who have already made substantial investments in pollution control technology, when such utilities should be rewarded for having made the decision to install pollution control equipment before such equipment was required by law. In the case of Buckeye and its members, who operate on a nonprofit cooperative basis, these costs have been incurred 100% by their ultimate retail members/consumers. It is bad public policy for EPA to discourage utilities from making voluntary investments in pollution control technology, which discouragement will be the result if EPA's proposal is adopted. In the future, utilities will likely only take such minimal actions as are required by law in order to avoid being penalized for having done more than the law minimally requires. EPA has not explained why it has chosen this allocation methodology over more equitable and traditional formulas. [EPA-HQ-OAR-2009-0491-2710.1, p.5]
The proposal solicits comment for alternative approaches, and in particular an approach based on heat input. P. 45311. We urge EPA to adopt the allocation methodology similar to that promulgated in the CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This heat input driven system was not overturned by the court's decision in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). As this alternative is described in the proposal, allowances could be distributed pro rata under state allowance budgets based on unit historic heat input rates. Several subcategories may be developed, such as coal and natural gas generation, with allowances distributed based on state allowance budgets and historic heat input within each subcategory. [EPA-HQ-OAR-2009-0491-2710.1, p.5]
Using historic actual emissions as the basis for allowances punishes early adopters of emission controls. Obviously, baseline emissions will be lower for a unit equipped with pollution controls. EPA's preferred CATR approach would penalize that facility by allocating to it fewer allowances. A heat input approach, unlike an emissions-based approach, would eliminate perpetual allocations to the highest emitting units, and does not punish consumers who have paid for investments in emission control equipment, thereby effectuating a rational policy. This method would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-2710.1, p.5]
2. A multi-year test period should be used.
Furthermore, a multi-year database, rather than a single test year, is appropriate. It appears that EPA's preferred approach is to allocate allowances based upon historic emissions, using a single test year. Using a single test year is particularly onerous for a relatively small utility like Buckeye. With only a few units, operational aberrations may occur in any single year. The unit could be out of service, thus greatly reducing the emissions for that year. If environmental controls were already installed, they could be having a high performance year, resulting in abnormally low emissions. Buckeye's SCR systems, for example, performed at extraordinarily high control efficiencies in 2006-2007. It is unrealistic and unreasonable to assume that such performance can be sustained. Using a multi-year test period is much more fair and will reduce the impact of such aberrations. For the same reasons, if EPA adopts Buckeye's preferred heat input approach, a multi-year period should be used to determine the appropriate heat input factor. For large utilities with many units, a single test year may be more appropriate than with smaller utilities such as Buckeye, since larger utilities can absorb abnormalities in emissions or control efficiencies within their control technology over a greater number of units; Buckeye, on the other hand, with two units, cannot absorb abnormalities in emissions or control efficiencies since Buckeye does not have as many units to average these abnormalities. The risk of such anomalies must be reduced by lengthening the 'base' period. [EPA-HQ-OAR-2009-0491-2710.1, pp.5-6]
As with EPA's setting of NOx allowances under CAIR, allowance allocations for SO2 and NOx should be updated every five years to reflect a unit's highest three of five years of heat input. [EPA-HQ-OAR-2009-0491-2710.1, p.6]
c. EPA's proposal does not allocate sufficient allowances to allow utilities to operate their facilities with best available emission control technology installed.
The following table identifies the actual annual NOx emissions from Cardinal Unit No. 3 for 2005 and 2009, as well as EPA's proposed annual NOx emission allowances for 2012 and 2014 under CATR:
[Table can be found on page 8 of this comment] [EPA-HQ-OAR-2009-0491-2710.1, p.8]
Buckeye will be allocated annual NOx allowances below those required to operate its units even when they are fully controlled with best available pollution control technology. Cardinal Unit No. 3 had best in class SCRs installed in 2003, and its actual NOx emissions in 2009, when its SCRs were operating on a full year basis, rather than a seasonal basis as in 2005, were 883 tons. These were among the best performing SCRs in the country, with a 93.4% removal rate that year. In fact, the Cardinal Unit No. 3 SCR has ranked in the top decile of SCR performance nationwide every year since 2004. Nevertheless, for 2012 year, Buckeye has been allocated only 621 NOx allowances for Cardinal Unit No. 3; however, Buckeye's emissions exceeded those levels in 2009 even with best in class SCRs already installed. Buckeye's SCR performance is likely to decline over time from its base year performance, since Buckeye's SCRs only recently began year-round operation. A utility that has installed best available control technology should be allocated enough allowances to operate with BACT installed. [EPA-HQ-OAR-2009-0491-2710.1, pp.8-9]
The following table sets forth actual annual 2005 and 2009 SO2 emissions for Buckeye's Cardinal Unit Nos. 2 and 3, as well as proposed SO2 annual emission allowances for such units under the EPA's CATR proposal:
[Table can be found on page 9 of this comment] [EPA-HQ-OAR-2009-0491-2710.1, p.9]
Cardinal Unit No. 2 had FGD equipment installed in 2008, and its actual SO2 emissions in 2009, when its SCRs were operating on a full year basis, were 4,273 tons. Nevertheless, for 2014 year, Buckeye has been allocated only 4,205 SO2 emission allowances for Cardinal Unit No. 2; however, Buckeye's emissions exceeded those levels in 2009 even with JBR FGD equipment already installed. A utility which has installed best available control technology should not be allocated less allowances than are required to operate with BACT installed. [EPA-HQ-OAR-2009-0491-2710.1, p.9]
This unfair allocation is the result of EPA's use of historic emissions rates and a single test year, rather than heat input and a multi-year test year, as the baseline. Buckeye should not be punished for having already installed BACT. Ohio cooperative members/consumers have already spent or will soon spend approximately $1 Billion to install state of the art high performing pollution control equipment for NOx and SO2 on 100% of their base-load coal fired generation. Ohio cooperative consumers should not be required to curtail operations and purchase replacement power, nor to acquire additional emission control allowances (if any are available under CATR), in order to meet EPA's mandates under CATR. Since Ohio cooperatives have already installed or will soon install best available control technology for SO2 and NOx on 100% of their coal-fired generation, it is unreasonable and unfair to require them to do more, when other utilities have not yet undertaken the steps that Buckeye already has or will soon complete. [EPA-HQ-OAR-2009-0491-2710.1, p.9]
d. EPA's CATR proposal will punish existing units with high performing emission controls and reward units that have not invested in adequate emission control technology.
According to EPA's database, the WH Sammis units (Stratton, Ohio) are equipped with SNCR control systems. EPA has allocated the WH Sammis plant 3.22 tons of annual NOx per MW of capacity. But Buckeye's Cardinal Units have been allocated 1.2 tons of annual NOx per MW of capacity. The SNCR NOx control system is less expensive and less efficient than Buckeye's SCR NOx emission control system. Nevertheless, Buckeye's Cardinal Units have been allocated less NOx emission allowances than the Sammis units because Buckeye's Cardinal Units have more expensive and more efficient NOx emission control equipment, which establish lower historic baseline emissions than the Sammis units. This is patently unfair and unreasonable. Buckeye should be rewarded, not punished, for having installed state of the art and high performing SCR equipment. [EPA-HQ-OAR-2009-0491-2710.1, pp.9-10]
In addition, the JM Stuart units have been allocated a total 1.9 tons of annual NOx per MW of capacity, whereas Buckeye's Cardinal units have been allocated only 1.2 tons of annual NOx emissions per MW of capacity. In this case, Buckeye's Cardinal units and the Stuart units have similar SCR systems installed and therefore the two facilities should be allocated similar emission allowances. However, EPA has provided less allowances to Buckeye's Cardinal Units than to the Stuart units. This is arbitrary and unreasonable. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Furthermore, uncontrolled units have received significantly higher proposed allocations than Buckeye's controlled units. Examples include the Gorsuch plant, which has been allocated 10.36 tons annual NOx/MW, the RE Burger facility, which has been allocated 14.2 tons annual NOx/MW, and the Eastlake plant, which has been allocated 6.06 tons annual NOx/MW, whereas Buckeye's Cardinal Units were allocated only 1.2 tons annual NOx/MW. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Similarly, Buckeye was penalized and provided significantly less SO2 allocations as compared to uncontrolled units. Buckeye's Cardinal Units received 7.15 tons of SO2 (2014 and beyond) per MW of capacity; whereas the uncontrolled units at Sammis received approximately 14.5 tons/MW. Other uncontrolled units received larger allocations of SO2 on a ton/MW basis. Examples include the Gorsuch Plant at approximately 26.1 tons SO2/MW, RE Burger at 30.62 tons SO2/MW, and the Eastlake plant at 15.63 tons SO2/MW. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Moreover, our preliminary evaluation of the additional data from the NODA suggests that these circumstances will become even more pronounced. While allocations have not been published for the revised model, it appears that using the NODA data and inputs, the allocations of SO2 allowances to Buckeye's Cardinal Units will be cut in half. As noted above, Buckeye anticipates submitting additional comments on the NODA materials and information. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Each of these examples illustrates the inequity in the current EPA proposed CATR, which rewards the units that have not invested in BACT, and punishes those that have. Why should Buckeye's controlled units receive less emission allowance allocations than uncontrolled units, when the reason Buckeye and its members are receiving less emission allowances is because they incurred substantial costs to install state of the art and high performing emission control equipment, i.e. JBR FGD equipment and SCR equipment? This result is bad public policy and will not encourage future investments in pollution control equipment absent a mandate. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
e. Natural gas peaking units must be allocated allowances at the lesser of their actual or permitted emission levels in order to allow them to support grid reliability and meet peak demand as and when needed.
With respect to Buckeye's natural gas-fired peaking units, the Greenville Station and the Robert P. Mone Plant, actual NOx emissions for the Greenville Station were 26 tons in 2007, and actual NOx emissions for the Mone Plant were 27 tons in 2007. Under EPA's CATR proposal, the Greenville Station has been allocated 14 NOx allowances, and the Mone Station has been allocated zero NOx allowances. These are clearly insufficient allowances to allow these plants to operate normally. Buckeye's natural gas-fired peaking plants should be allocated sufficient NOx allowances to allow them to operate up to the lesser of their operating permit limits or actual emissions. [EPA-HQ-OAR-2009-0491-2710.1, p.11]
Using historic emissions and a single test year for Buckeye's peaking units is not going to allocate sufficient NOx emission allowances to allow these peaking units to operate the number of hours that will be needed when load and economic conditions improve, or when more extreme weather conditions such as those experienced in the abnormally hot summer of 2010 require the increased dispatch of peaking capacity. Whereas Buckeye's baseload coal-fired units have continued to operate near their historic levels of output during the recent recession, Buckeye's peaking units have not. Baseload units must operate at minimum loading levels or not at all. On the other hand, peaking units are designed to operate only when needed to meet peak load demands. Accordingly, during these recent recessionary times and relatively mild summers of 2008 and 2009, Buckeye's peaking units have not been operating nearly as many hours as they will be needed when the economy and load improves or when extreme temperatures increase the demand for electricity. Since peaking units are critical to grid reliability and only contribute minimally to NOx emissions (being classified as Minor Sources), Buckeye's peaking units should be allocated sufficient NOx emission allowances to allow them to operate up to the lesser of their actual emissions or their permitted limits, which will be needed as the economy improves and these units are called upon to support grid reliability and meet peak load demands. [EPA-HQ-OAR-2009-0491-2710.1, p.11]
Buckeye's Peaking Units Require Increased Allowances
Although Buckeye's Robert P. Mone and Greenville Station natural gas-fired peaking units appear to be allocated some additional allowances under the NODA model (although it is hard to confirm this as EPA has not provided new specific unit allocations for NOx and S02 emission allowances using the updated assumptions contained in the NODA data), they still are not allocated sufficient NOx allowances to allow them to operate consistent with historical practices and up to their permitted limits. Buckeye reiterates its CATR comments that peaking units must be allocated sufficient allowances to allow these minor sources of emissions to operate at the lesser of their actual emissions levels or their permitted limits. Peaking units must be available to function in their critical role of maintaining grid reliability at times of peak demand. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.6]
For all of the foregoing reasons, Buckeye Power urges EPA to withdraw its proposed CATR program. If it does proceed, EPA should (1) base its allocation of allowances on heat input rather than historic emissions; (2) employ a multi-year test period, rather than a single test year, for calculating allowance allocations; (5) allocate sufficient emission allowances to units with best available emission control technology already installed or to be installed, so that such units can operate normally and without needing to acquire additional allowances (if any are available under CATR) or to curtail operations; (6) allocate sufficient NOx emission allowances to natural gas-fired peaking units to allow them to operate up to the lesser of their actual emissions or their operating permit limits; and (7) incorporate into CATR existing emission control allowances acquired under CAIR and prior law. [EPA-HQ-OAR-2009-0491-2710.1, p.13]
Calpine Corporation
Calpine believes that the proposed rulemaking could better promote the goal of reducing SO2 and NOx emissions from the electricity sector and level the playing field for companies that have invested in air pollution controls. EPA should develop an allowance allocation mechanism that does not financially harm the very units that are critical to reducing overall emissions from the electric generation sector - namely modern national gas-fired units and other units that have invested in pollution controls. Specifically: [EPA-HQ-OAR-2009-0491-3614, pp.2-3]
:: The current EPA unit allocation method is based on emissions. This approach rewards older, dirtier units.
:: The current EPA unit allocation method is not updated based on changes to future generation patterns. This static allocation does not provide sufficient allowances to low- emitting units that are expected to increase their capacity factor over time.
:: When combined with indefinitely fixed allocations, the limitations on interstate allowance trading create the potential for anti-competitive behavior in some states if large generators hoard their allowances.
:: Using dispatch models such as IPM as the basis for allowance allocation will disadvantage units that have power purchase agreements in place as well as those in transmission-constrained regions.
:: There are a several inaccuracies related to Calpine units in the EPA allocation database. [EPA-HQ-OAR-2009-0491-3614, p.3]
EPA Should Distribute Allowances Using Output-Based Allocation
Calpine objects to EPA's allocation method that is based on historic emissions because it rewards older, dirtier units and penalizes cleaner, more energy efficient units. We prefer an updating, fuel-neutral, output-based allocation scheme. Output-based allocation (i.e. basing allocations on electricity production) allows units that have invested in air pollution controls to recoup a portion of their investment. Output based allocation encourages the dispatch of cleaner, more efficient units to the overall benefit of ambient air quality and in support of the emission reduction goals of the proposed rulemaking. Such emissions reductions have been achieved in states that have adopted output based allocation in state implementation plans (SIP) for other cap and trade programs such as CAIR and the NOX SIP Call. [EPA-HQ-OAR-2009-0491-3614, p.3]
If it is not feasible to promulgate a rule featuring output-based unit allocation then Calpine urges EPA to allocate allowances to units based on historical heat input. Allocating to units based on heat input could be accomplished by determining each unit's pro rata share of the total state heat input then multiplying by the total state emissions budget. Such an approach would drive emissions reductions and ensure that less polluting units do not have an allowance shortfall. [EPA-HQ-OAR-2009-0491-3614, p.3]
Calpine believes that a heat input allocation approach is responsive to the Court ruling. Specifically, the Court objected to EPA's use of fuel allocation factors finding:
' ... states with mainly oil- and gas-fired EGUs will subsidize reductions in states with mainly coal-fired EGUs.' [EPA-HQ-OAR-2009-0491-3614, pp.3-4]
The Court reached this decision in the context of the state allowance budget allocations -- a prcblem EPA has fixed in the proposed rulemaking by determining each state's contribution to downwind nonattainment. The Court offered no opinion on the unit specific allocation methodology except that it was borne of a flawed state allowance allocation scheme. Thus, EPA is not precluded from allocating allowances to units using the heat-input approach. [EPA-HQ-OAR-2009-0491-3614, p.4]
EPA Should Discourage Anti-Competitive Behavior
There are several states affected by the proposed rulemaking where an inordinate amount of allowances were allocated to a single company. Because interstate trading is limited under the proposed rulemaking, Calpine is concerned that some companies may exhibit anti-competitive behavior and hoard allowances to the detriment of companies that need a liquid market in order to purchase allowances for compliance. This concern is amplified when combined with the proposed concept of allocating allowances in fixed quantities for indefinite periods. For Calpine, this presents a significant concern given the isolated nature of some of our facilities outside of California and Texas. EPA should consider additional mechanisms beyond the limited interstate trading to help companies that may be victimized by anti-competitive hoarding behavior. Calpine supports EPA's option of a limited auction to help with market liquidity. [EPA-HQ-OAR-2009-0491-3614, p.4]
Problems with Basing Allocations on Dispatch Modeling
IPIM is a complex model that attempts to simulate unit behavior in a deregulated electricity market. Unfortunately the electricity market is not fully deregulated and unit operation is dictated by additional factors, most significantly energy purchase agreements and local grid reliability considerations. Calpine is the largest provider of CHP in the country and most of these units have steam sale contracts and power off-take agreements that require the units to operate more than may be predicted by a simulation model. In addition, ERCOT is transitioning to a nodal market that could further restrict electricity flow by affecting local pricing and dispatch. [EPA-HQ-OAR-2009-0491-3614, p.5]
Consider the following examples. Our Carville (LA), Morgan (AL), and Decatur (AL) facilities operate under long term contracts and historic annual heat input of these plants are all above 20 X 106 MMBtu. Yet the IPM model predicts future heat input for these plants with be less than 1.1 X 106 MMBtu per facility, well below levels that will allow Calpine to fulfill its contractual obligations. [EPA-HQ-OAR-2009-0491-3614, p.5]
EPA should consider using the greater of historic heat input and modeled future heat input when apportioning allowance budgets or otherwise allow sources that will have higher than predicted future capacity factors attributable to long term contracts to obtain an increased allowance allocation such as a long-term contract allowance set-aside similar to the new source set-aside. [EPA-HQ-OAR-2009-0491-3614, p.5]
City of Dover, Delaware
The City is concerned that limiting interstate allowance trading will be particularly disadvantageous to small states, such as Delaware, in which there are fewer covered units thus leaving each more exposed to potential short falls of allowances in a given year. Where a larger state, with a diverse mix of electric generating sources and higher total allowance caps, might be better positioned to absorb fluctuations in the allowance markets, smaller states may be constrained by lower total allowance volumes resulting in rate spikes for customers. This is of particular concern for peaking units and states such as Delaware for which peaking capacity is the vast majority of its supply (Delaware imports the majority of its base load supply). This issue is particularly acute if allowance allocations remain as they are under the proposed methodology. At current proposed allocation levels if the City were required to run their two covered peaking units extensively in a year, forcing them to procure allowances in the marketplace, they may find limited supply in a small state such as Delaware. Greater flexibility to trade with generators from other states, above the variability limits currently proposed, would help protect generators in smaller states. [EPA-HQ-OAR-2009-0491-2636.1, p.3]
In order to limit the costs of electricity service to its customers, the City has developed a strategic plan for managing their compliance requirements under CAIR. Part of this plan depends on a reliable source of SO2, NOx annual, and NOx seasonal allowances allocated by program administrators. In addition, prudent management of Dover's requirements under these regulations requires that Dover bank a portion of their allowances for future years as a hedge against spikes in allowance prices and the volatile nature of the dispatch of their peaking units year to year. Under the proposed Transport Rule, the City has serious concerns as to the lack of fungibility of CAIR allowances and the allocation methodology that significantly reduces the number of allowances allocated each year. Under this new structure the City's customers will be unnecessarily exposed to increased electricity costs. [EPA-HQ-OAR-2009-0491-2636.1, p.1]
Under the Transport Rule, covered units receive allowance allocations equal to the lesser of their total 2009 emissions and their total projected 2012 emissions based on EPA's Integrated Planning Model (lPM). The City feels that this methodology insufficiently reflects emission levels for smaller peaking units. The amount of time a peaking unit runs is determined by a number of factors and often varies greatly from year to year. Higher temperatures and increased industrial production often leads to higher electricity demands requiring peaking units to run more frequently. With electricity demand generally lower during 2009 from a receding economy and relatively mild temperatures, peaking units were not required to run as frequently. These factors led to low 2009 emission levels, particularly for peaking units. [EPA-HQ-OAR-2009-0491-2636.1, pp.1-2]
Using the City's units as an example, during all of 2009 the two units ran a total of 174 hours. By way of comparison, through the end of August 2010, the same two units have already run 782 hours. Reviewing other years' generation levels further supports the proposition that 2009 was an abnormally low generation year - the City's two units ran 507 hours and 396 hours in 2006 and 2007 respectively. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
Peaking units play a critical role in overall electricity system reliability and security. By restraining these units with insufficient allocations, EPA threatens to damage system reliability and customer needs for electricity. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
The City feels that a baseline period averaged over a larger period of time, greater than 1 year, would more accurately reflect the reality that peaking units have varied emission levels from year to year. The City recommends using a 5 year baseline period for determining unit allocations. A 5 year time period would provide a more realistic baseline, allowing abnormally high and low generation years to be accounted for and normalized. While the City appreciates the need to set unit allocations and state budgets levels designed to achieve attainment of National Ambient Air Quality Standards (NAAQS), using a singular year for determining baseline allocations has the potential to, and in this case does, disproportionately restrain peaking units. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
City of Tallahasse
The Penalty for "Getting Clean Early" and Baseline Years.
Over the last ten years, the City of Tallahassee has made significant efforts to voluntarily initiate programs to reduce their emissions of NOx, SO2, PM, and Ozone.  Many of these efforts were done to reduce emissions prior to the implementation of different regulatory programs that at the time had not been fleshed out: mandatory greenhouse gas reduction programs, regional haze, and CAIR, just to name a few.  Utilities like the City of Tallahassee, that include environmental protection in all their decision making processes often initiate voluntary reductions prior to future potential enactment of environmental regulations.  Specifically, the City has implemented a number of major electric generating improvements that have significantly improved the efficiency and environmental profile of its two power generating facilities.  These include the construction of Combined Cycle Combustion Turbine Unit No. 8 at the Sam O. Purdom Electric Generating Station (ORIS Code 689), two Sprint Combustion Turbines at the Arvah B. Hopkins (ORIS Code 688) Electric Generating Station (Hopkins), and the repowering of Unit No. 2 at the Hopkins Plant from a conventional steam boiler to a combined cycle unit. The City has installed SCR on the two combustion turbines and the combined cycle unit at Hopkins.  Had the City chosen not to do so, it would have been "rewarded" with additional allowances that the City could bank or sell.  This is a huge disincentive for companies to enact positive environmental benefits before regulatory mandates. [EPA-HQ-OAR-2009-0491-2669.1, pp.2-3]
Clean Energy Group
The language of the Clean Air Act provides EPA with broad authority to implement any of the alternative allocation methodologies set forth in the proposed rule or recommended below. Section 302(y) states that a FIP 'includes enforceable emission limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances), and provides for attainment of the relevant national ambient air quality standard.' However, while EPA has significant latitude with regard to choosing an allocation structure, the methodology proposed is based on data with notable inaccuracies. The Clean Energy Group is concerned that there is not sufficient time and resources for the final rule to reflect all of the necessary corrections to the underlying data to ensure the rule is based on a legally sound allocation approach. A program that is based on erroneous data and is unnecessarily complex could cause a court to deem it arbitrary and capricious, leading to further delay in addressing air pollution transport. EPA should also consider what methodology will best accomplish the goals of Section 110 - to encourage the most cost-effective emissions reductions and drive investment in the technologies necessary to address transport and nonattainment on a long-term basis.  [EPA-HQ-OAR-2009-0491-2702.1, pp. 4-5]
The Clean Energy Group Does Not Support Allocating Allowances to Units Based on Projected Emissions
While the Clean Energy Group supports the proposed methodology for developing state budgets, it does not support the proposed methodology for allocating allowances to units. The Clean Energy Group recommends an alternative to the use of projected emissions from IPM runs as the basis for unit-level allocations in 2012,2014, or future recalculations for the reasons discussed below. IPM does not consider a range of non-economic factors that may influence a company's decision to operate particular types of units or for the respective Independent System Operator (ISO) to call upon specific units. As a result, the modeling creates unrealistic scenarios for some individual units, such as ignoring dispatch requirements of EGUs subject to power purchase agreements, running natural gas combined cycle units at higher utilization than can be accommodated by the local natural gas pipeline network, and not running oil-fired units that are required to operate to meet load requirements. These distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets, but result in unrealistic or infeasible outcomes when used at the unit level to allocate allowances. As we note above, the Clean Energy Group believes it is important for EPA to propose a rule that withstands, and preferably forestalls, litigation and that can be implemented as quickly and smoothly as practicable. We are concerned that even with EPA's best efforts to correct the underlying data, allocating allowances to units based on projected emissions is not appropriate, and creates an unnecessarily complex system that has the potential for flaws that the rulemaking process cannot address in time to implement the program in 2012. The proposed approach could create a number of erroneous or anomalous results that could cause courts to deem the program arbitrary and capricious.  [EPA-HQ-OAR-2009-0491-2702.1, p. 5]
Further, by basing unit allocations for 2012 on a methodology that assumes an owner will operate installed or planned pollution control technologies at maximum emission control rates, EPA is penalizing companies that have made the capital investments needed to control emissions while rewarding companies that are not controlling emissions. As EPA states in the preamble to the proposed rule, 'this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment.' This result is counterproductive to EPA's overarching goal of driving investment in strategies to improve environmental performance. [EPA-HQ-OAR-2009-0491-2702.1, p. 5]
Therefore, the Clean Energy Group recommends that EPA modify the unit allocation scheme. There is no strong policy or legal reason that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. Below, the Clean Energy Group proposes alternative unit allocation approaches that are consistent with the D.C. Circuit's decision because they do not alter the state budgets, which are based on each state's significant contribution. Additionally, the proposed approaches are fuel-neutral and would not raise the concerns identified by the court regarding CAIR's use of fuel adjustment factors. [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
Alternative Allocation Methodologies to Promote Cost-Effective, Consistent Emissions Reductions
In order to ensure the data underlying the allocations to units are legally sound, we propose that EPA adopt a historic basis for unit allocations, such as historic output or heat input, which could be adopted without additional notice and comment. Many of the Clean Energy Group companies have long supported output-based allocation approaches. An output-based allocation relies on energy production (megawatt-hour [MWh]) as the basis for determining the number of allowances that a unit will receive prior to the compliance year. For example, if a unit generates 10 percent of the electricity produced by covered units, it would receive 10 percent of the available allowances. The benefits of an output-based allocation include promoting more efficient and cleaner production of electricity. In addition, the methodology does not further penalize companies and their customers for investments made in cleaner generation prior to a regulatory mandate.  [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
Given EPA's use of historic heat input in previous allocation proposals, the Clean Energy Group also supports allocating allowances to units based on a unit's pro rata share of its state's historic heat input (i.e., million British thermal units [mmBtu]), as was originally proposed for CAIR, prior to the introduction of the fuel adjustment factors. We note that the D.C. Circuit invalidated the use of fuel adjustment factors, not the use of historic heat input. The historic heat input should be based on the maximum annual heat input for units during the period of calendar years 2007 through 2009. We recommend using the annual maximum of reported data during the three-year period rather than the average of those three years in order to ensure an outlier year does not dramatically affect the allocation (e.g., the unusually low utilization in 2009). In cases where an owner has not reported heat input data for one or all 0 f the years, we propose that EPA allow the owner to submit such data for consideration, provided that the data are of equivalent quality. [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
Such an allocation methodology would address many of the Clean Energy Group's concerns with EPA's preferred approach. Most significantly, it would not be based on modeled future emissions with its known inaccuracies for some types of units that may dispatch for noneconomic purposes and would be based on verified data EPA already holds. Additionally, this approach would correct the proposed methodology's disadvantages for early actors that EPA acknowledges in the proposal. [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
It is important to note that the Clean Energy Group is proposing this approach with the goal of EPA implementing the Transport Rule by January 1,2012. Thus, we would welcome the opportunity to discuss and provide feedback on any additional allocation approaches suggested in other stakeholders' comments. However, the Clean Energy Group companies oppose an allocation approach based solely on historic emissions. Emissions-based allocations, similar to the fuel-adjusted heat input-based allocation rejected by the D.C. Circuit, reward higher-emitting facilities at the expense of early actors and discourage future early action by companies. Penalizing early actors and rewarding high-emitters is exactly the wrong signal EPA should send to industry as the Agency works to develop and implement multiple regulations for the electric sector and other industries. [EPA-HQ-OAR-2009-0491-2702.1, pp. 6-7]
The allocation methodology for 2014 and thereafter must send a clear and long-term price signal to drive the installation of cost-effective emission controls to address air transport. If EPA allocates allowances to units based on historic output, historic heat input, or a combination of the two, the Clean Energy Group recognizes flexibility in 2012 and 2013 may be necessary. This flexibility during the transition period could include, for example, EPA's proposed unlimited interstate trading or an alternative allocation methodology that transitions to a historic heat input allocation. We agree with EPA that as-yet-unplanned controls cannot be implemented before 2014 and, therefore, the 2012 to 2013 transition period must seek lock in the expected gains from CAIR, rather than drive additional reductions. This transition period must ensure air quality does not backslide from what CAIR has accomplished, or would have accomplished before 2014, while allowing companies to plan for further necessary emissions reductions beginning in 2014. [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
Future-Year Unit Allocations
Finally, EPA must propose a clear and uniform mechanism to reduce unit allocations when necessary (e.g., when future NAAQS revisions result in lowered state budgets). Regardless of EPA's ultimate allocation methodology, transparency will be essential to continued stakeholder support. The alternative allocation methodology proposed above will facilitate such a mechanism in a clear and transparent manner that also drives emission reductions, in support of the aims of Section 1l0(a)(2)(d).  [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
While the proposed Transport Rule is silent on how a revised NAAQS would affect future state budgets, we believe that clarity on this issue in this rulemaking is imperative to ensure an efficient emission allowance market with proper price signals for unit operations, pollution control investments, and retirement. Prolonging this uncertainty until [mal promulgation of a future Transport Rule would only weaken price signals and stifle incentives to invest in cleaner generation.  [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
Some members of the Clean Energy Group are concerned that the proposal's fixed allocation methodology would disadvantage clean generating units whose utilization is expected to increase over time. To address this problem, EPA could update unit allocations for non-retired units every three years to account for changes in utilization. Other members of the Clean Energy Group recommend that EPA's incorporation of the auction provisions proposed in these comments, below, is sufficient to address changes in generation. [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
Peaking Units and Rounding Conventions
a. Auction the Clean Energy Group recommends that EPA establish a small auction of allowances that is initially similar in size to the proposed new unit set aside. Similar to the small auction in the Acid Rain Program in structure and implementation, an auction would promote price discovery and liquidity. Although the Clean Energy Group believes that market manipulation would be a greater risk under EPA's proposed Alternative 1 than under the preferred alternative, we are concerned that the limited trading under the preferred option has the potential to result in some market manipulation in isolated areas. An auction would mitigate these concerns. Additionally, we propose below that EPA consider shifting excess allowances from retired units to the auction rather than the new unit set aside. An auction that gradually increased in size would phase-in a more level playing field for all emission units in terms of allowance pricing. A growing auction would likely also further drive investment in control technologies by higher emitting units. Finally, owners who have already incurred the cost of installing and operating control technologies would benefit by needing to purchase relatively fewer allowances at auction. [EPA-HQ-OAR-2009-0491-2702.1, p. 8]
The Clean Energy Group is also concerned that EPA's proposed methodology disadvantages natural gas peaking units relative to higher-emitting units, in clear contrast to the emissions reduction goals of Section 110. Because these units have low annual emissions and only run at times of high demand, the IPM model projects S02 emissions of slightly less than 0.5 tons. Based on the proposed methodology, EPA would round these allocations to zero when calculating the unit's allowance allocations. If EPA retains the preferred allocation methodology, the Clean Energy Group recommends that EPA at least round these units' allocations to one ton (in contrast to the zero proposed) so as not to discourage use of cleaner fuels during periods of peak demand. [EPA-HQ-OAR-2009-0491-2702.1, p. 8]
If EPA agrees to modify the unit allocation methodology as the Clean Energy Group recommends, EPA may need to consider whether to also adjust the method for calculating the surrender requirement for complying with assurance provisions. The proposed rule links a unit's allocation and the assignment of responsibility for the assurance provisions, but this linkage may or may not be appropriate depending on the final allocation methodology. [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
Treatment of Retired Units' Allocations
The Clean Energy Group supports EPA's proposal to continue to allocate allowances to retired units for six years after ceasing operations. The six-year period ensures that companies make retirement decisions independent of any allocation and allowance value. However, rather than placing these allowances in the new unit pool or redistributing these allowances at the end of the six-year period, the Clean Energy Group recommends that EPA use these allowances to increase the auction pool over time. [EPA-HQ-OAR-2009-0491-2702.1, p. 8]
Corrections to the Modeling Assumptions
When reviewing EPA's modeling assumptions and results, the Clean Energy Group companies have noted a number of incorrect assumptions and unrealistic results (e.g., pollution controls assumed but not planned, units not projected to run that are contractually required to, etc.). To address unit level data issues and potential inaccuracies, individual Clean Energy Group companies will submit separate comments with technical corrections on a unit basis in separate comments to EPA. There are a number of other issues that cannot be appropriately handled by the model. For example, Clean Energy Group companies have:
-units with power purchase agreements that are modeled as having a lower heat input than is required to fulfill contractual requirements,
-units located in load pockets with high demand that are modeled as having a lower heat input than has historically been required to maintain reliability, and
-units that are modeled to run on natural gas at rates that exceed local pipeline capacity. [EPA-HQ-OAR-2009-0491-2702.1, pp. 8-9]
Another area of particular concern is the model's treatment of dual-fuel oil and gas units. During a July 7, 2010, EPA briefing hosted by the Edison Electric Institute (EEl), EPA staff acknowledged that IPM has difficulty handling dual-fuel units because there are non-economic reasons that a company must run such units that the model is not capable of considering. The Clean Energy Group strongly encourages EPA to correct this modeling limitation through adjustments to the model or through post-modeling adjustments to unit emissions. We also note that this issue is not limited to dual-fueled units, and would be resolved by allocating according to our proposed methodology. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
These issues provide clear examples of why EPA should move away from the model-based approach to allocating allowances and toward a historic basis as recommended by the Clean Energy Group. If EPA elects not to change the allocation approach, then EPA will need to make the necessary adjustments to the model or its output. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
We also recommend that prior to finalizing the Transport Rule, EPA release as soon as feasible a Supplemental Notice of Proposed Rulemaking and/or additional Notice of Data Availability (NODA) that allows owners of covered units to verify the data underlying the allocations in the final rule and provide any necessary comments to correct the data. For example, if EPA decides to retain the proposed allocation methodology, the Clean Energy Group recommends that EPA release the updated assumptions and modeling results used as the basis for the allocations, along with revised unit allocations. Such a process would ensure the final data underlying the rule are as accurate as possible by providing stakeholders with an opportunity to submit additional corrections. This effort could occur while EPA is drafting other provisions of the final rule and thus would not delay release of the final rule in early 2011 or implementation on January 1, 2012. It would, however, improve the accuracy of and the confidence in EPA's underlying data. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
The Clean Energy Group has historically preferred a legislative solution that reduces ozone and particulate concentrations in the Eastern U.S. through unlimited interstate trading because market-based programs provide the most cost-effective reductions. However, we recognize that EPA is constrained from allowing unlimited interstate trading. EPA's proposal remains within the constraints of the D.C. Circuit's decision while offering as much trading as possible under Section 110. Legislation granting EPA authority for regional trading is likely the only way to allow an unlimited trading system that ensures the most cost-effecive reductions.  [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
The preferred option manages to allow some interstate trading while staying within the constraints of the D.C. Circuit decision by ensuring the necessary emissions reductions occur in the states identified as contributing to nonattainment or interfering with maintenance in other states. At the same time, the preferred option allows owners to use market mechanisms to buy and sell allowances. Allowance markets are essential to promoting cost-effective reductions.  [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
Cleco Corporation
B. Unit Allocations Should Have Firm Basis in Actual Emissions Data.
Cleco is troubled by EPA's sole reliance on projected data, in some cases, to set unit allocations. As noted above, unit allocations should be left to the individual states, who understand the unique aspects of electric generation within their jurisdiction. But should EPA persist with imposing a FIP, it should ground unit allocations in actual emissions and dispatch data. To the extent EPA relies on projected data, at all, it should do so cautiously. Predicting fuel costs, dispatch etc. involves numerous variables, which if imprecise can lead to unrealistic projections. Based on what we have been able to determine at this point, EPA's IPM projections lead to allocations that simply do not reflect reality  -  as evidenced in Louisiana's NOx allocations. At this point, we caution EPA against relying too heavily on its own projections to set unit allocations. We will continue to review this issue in the context of EPA's new IPM runs provided with the NODA and will refine this comment, as appropriate. [EPA-HQ-OAR-2009-0491-2859.1 p.8]
Connecticut Department of Environmental Protection
EPA's allocation methodology is inconsistent and does not reflect reality. The Integrated Planning Model (IPM) has historically been used to predict large regional trends in EGU operations and the associated emissions from these stationary sources. IPM results at the state and local levels are less reliable and using IPM for predicting operations of individual EGUs is simply not accurate. For example, the IPM Base Case model run for 2012 projects that the 9 oil/gas LFBs in Connecticut (see Table A-4) will not operate in 2012. However, all 9 LFBs have already bid into the ISO-NE Forward Capacity Market through May 2013 and are contractually obligated to be available through that date, making it highly unlikely that they will cease operations by 2012. Furthermore, 8 of the 9 LFBs are contractually obligated to be available in the Forward Capacity Market through May 2014 (only Bridgeport 2 is not contractually obligated through May 2014). [EPA-HQ-OAR-2009-0491-2780.1 p.15]
[[Data Table Here]]
The IPM also led to incorrect source specific allowance allocations. The EPA proposed allocation to AES Thames is 847 SO2 allowances in 2012 based on IPM projections. EPA identified this allocation because AES Thames does not have reported SO2 data in the CAMD data system. However, AES Thames reported SO2 emissions to CTDEP in 2009 were 2298 tons (see Attachment D). AES Thames units operate under permits that require flue gas desulfurization accomplished by in-bed injection of limestone into the boilers for a minimum 75% SOx control efficiency. No additional controls are planned and cannot be reflected in 2012-2014 allocations. Furthermore, AES Thames operates under a long-term power purchase agreement that contractually obligates them to deliver their electrical output under a fixed price through 2015. The allocation to AES Thames must be corrected in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2780.1 p.15]
EPA has indicated that SO2 allocations to Bridgeport Station 3 are based on operating data during the 4th quarter of 2008 and the first 3 quarters of 2009. The 2009 operations of Bridgeport Station 3 were notably lower than previous years due to the cool wet summer, poor economic conditions and natural gas prices that pushed Bridgeport Station 3 down the bid stack.
The IPM is also internally inconsistent. It projected that LFBs will not operate in Connecticut in 20123 yet still allocated 634 SO2 allowances to these sources. In contrast to the IPM projections that all 9 LFBs in Connecticut will shut down by 2012, the IRP model, described in the Peak Emissions discussion above, projects a more rational outcome; that 4 LFBs (Bridgeport 2, Middletown 3 and Norwalk 1 & 2) may shut down in 2013 and 2 additional LFBs (Middletown 4 and Montville 6) may shut down in 2016. Given the poor correlation between the IRP and IPM models and the inability of the IPM to track the reality of contractual agreements such as long term power purchase agreements and the operation of the forward capacity market in ISO-NE, the IPM cannot accurately predict unit level operations and should not be used by EPA to base unit level allocations in Connecticut. [EPA-HQ-OAR-2009-0491-2780.1 p.16]
Given the demonstrated flaws inherent in the IPM, CTDEP recommends EPA utilize the IRP modeling data in Attachment C in its allocation methodology for the Connecticut LFBs. CTDEP also requests that EPA revise its NOx and SO2 allocations to Connecticut consistent with the data provided in Attachments B-D based on historical electricity output basis. Additional Connecticut-specific allocation issues are set forth in Attachment B.  [EPA-HQ-OAR-2009-0491-2780.1 p.16]
Consolidated Asset Management Services (CAMS)
In regard to the unit specific allocation methodology, we request that EPA allow for either a state-specific defined approach or a heat-input approach be taken instead of the current approach as detailed in the State Budgets, Unit Allocations, and Unit Emission Rates TSD including associated Allocation Tables. In the state-specific approach each state shall implement their own methodology for allocating the allowances as provided in the State Emission Budgets. This approach would allow each state to craft a methodology best fitted for its energy profile and future growth, with an allowance variability for defined interstate trading. The other approach to assigning unit-specific allocations is similar to the heat-input approach as described in Alternative allocation methods section of the proposed TR preamble, page 45311. This approach would allocate allowances to units based on a ratio of the unit specific annual heat input and the summation of each unit's heat input in the state with the State Emission Budget. This methodology could use 3-year average look-back approach to be calculated on an annual basis for future year allocations. Therefore, the State Emission Budget is being met, with an allowance variability for defined interstate trading, while the level of activity a unit exhibits is being properly captured in the allocation process. [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Unit Heat Input Approach Example Calculation:
Given, for example:
Unit 3-year average Heat Input (HHV) = 8,000,000 mmbtu State Total 3-year average Heat Input (HHV) from affected units = 1,200,000,000 mmbtu State Emission Budget = 75,000 tons of given Pollutant of Concern, taking into account new-unit set aside and other account subtractions. [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Calculation:
(8,000,000 / 1,200,000,000) * 75,000 = 500 Unit Specific Allocations of Pollutant of Concern [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Both of these approaches also allow for the state to apply a broader definition of an affected unit, as seen in some of the Northeastern states in regards to lowering the nameplate capacity threshold of an affected unit from 25 MW to 15 MW, without impacting the existing units that were not considered in the proposed unit allocations as defined in the State Budgets, Unit Allocations, and Unit Emission Rates TSD including associated Allocation Tables. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
Constellation Energy
One criticism of this approach is that it rewards companies that delayed installing controls and penalizes companies who controlled early, or invested in low-emitting generation in anticipation of tightening emission limits. Once the Transport Rule is promulgated, should EPA transition to an alternative methodology to address these criticisms, Constellation Energy urges that EPA refrain from schemes with frequent allowance allocation updating; those that provide incentive to delay coal unit retirement; or those that provide an incentive to increase utilization in order to capture more allowances via the updating process. [EPA-HQ-OAR-2009-0491-3613, p.2]
Council of Industrial Boiler Owners (CIBO)
The Transport Rule establishes a new SO2 trading program, independent of the existing Title IV program. EPA and others have touted the Acid Rain Program as an example of how market based regulatory programs can reduce the cost of emissions reductions. The underlying reason for this is that the Acid Rain Program set total emissions limits that were attainable with use of conventional emissions control technology and/or fuel selection so that cost effective over-control could be employed at some units and other less costly approaches could be used at other locations with use of emissions trading. EPA's proposed Transport Rule, however, imposes increased emissions reductions with the promise of continuing reductions in the future, and it openly limits the ability to broadly trade emissions allowances. Thus EPA has demonstrated how reliant market based programs are on basic requirements such as trading and cost effective over-control, and without those, market forces cannot function, as evidenced by the recent precipitous drop in SO2 allowance prices. [EPA-HQ-OAR-2009-0491-2751.1 pp.3-4; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.3, 10/15/2010]
The problem with the allowance allocation methodology being used by EPA to provide allowances under the Proposed Rule is substantially magnified by EPA's proposed restrictions on allowance transfer. By severely limiting opportunities for securing allowances necessary for compliance demonstrations, EPA would restrict the ability of sources to comply with allowance obligations by more cost effectively securing greater emission reductions at other sources. These restrictions are least pronounced for companies that operate multiple emission units, at least within the same state, since the freedom to transfer allowances among such units is greatest under EPA's various approaches. By contrast, smaller facilities with single affected units are afforded no such option. Where such sources also cannot cost effectively reduce emissions at the affected source because of the unique operating, design or fuel characteristics, as in the case of the waste coal-fired CFB units, such facilities may not be afforded any compliance option under the Proposed Rule.   [EPA-HQ-OAR-2009-0491-2751.1 p.4; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.3, 10/15/2010]
Allocations [EPA-HQ-OAR-2009-0491-2751.1 p.8]
EGUs allocation given to non- EGUs. [EPA-HQ-OAR-2009-0491-2751.1 p.8]
In some cases, EPA has incorrectly identified non- EGUs as covered units. EPA needs to carefully evaluate the facilities it included in the modeling as Transport Rule units and remove those that are inappropriate. [EPA-HQ-OAR-2009-0491-2751.1 p.8]
Allocations, including allocations in the NODA, are incorrect and will greatly increase costs for some sources. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4, 10/15/2010]
Allocations are incorrect because they are based on very erroneous assumptions. For example, in determining the proposed allowance allocations for affected EGUs, EPA relied on several considerations, including projected emissions. EPA attempts to project emission rates based upon its own assessment, reflective of integration between different modeled projections, of anticipated generating rates in the future. EPA's projections for future generating rates are closely linked to its assumptions concerning the future cost of electricity generation, with a major focus on fuel cost. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.4-5, 10/15/2010]
Base summary data shows cost curves and pricing for coal, waste coal, landfill, gas, etc. This is used in the model to determine dispatch. Some CIBO members run waste coal-fired units. EPA discusses waste coal in Chapter 11 of the documentation. In that Chapter, the pricing for waste coal is tied to DOE-EIA AEO 2010 supply curves. Yet, the coal supply curves set forth in Chapter 9  -  Appendix 9- 4 data reveal a code and a cost for waste coal but provide no economic supporting data or explanation. (In the model run between v3.02 and v4.10, the prices of waste coal on a cost per MMBtus goes from $1.29 MMBtus to $2.27/MMBtus. Reported waste coal costs have averaged $1.48/MMBtus but include additional cost beyond the fuel cost including FOB mine and transportation costs (i.e., coal combustion byproduct management and transportation). There are reported costs in the $0.82/MMBtu range. The incorrect cost assumptions distort the ultimate dispatch calculations, resulting in much lower total Btus/year, and as a result, the allocations are impacted. Data for one CIBO member indicated a 76% availability, which is below that facility's normal availability range. Further, that facility is contracted for power and its normal availability is significantly higher. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
Another example is that IPM did not consider whether sources have a contract, REC credits, or other reasons to run at higher availability. Ultimately, if dispatch and allocations do not reflect the reality of a plant's operations, a plant will be forced to purchase credits at whatever cost, if credits are available. As there is intrastate-only trading in the SO2 Group 1 States (PA, WV, OH and others), credits will be less available and compliance more costly. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
Allowance allocations should be consistent with previously established heat input rates, as reflected in historical data. The allocation methodology should also reflect appropriate equitable considerations, including a source's emissions characteristics, emissions control limitations, and fuel source. Consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility; this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source. [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
There is a concern about how EPA determined the emission rate/allowance rate for SO2, NOx and Ozone NOx. Emission rates are based on EPA's definition of highly cost effective controls -  made not on plant basis but on a model plant basis. In regard to the waste coal plants, the assumptions in the documents refer to bituminous coal, not waste coal from anthracite or bituminous operations. Since the waste coal plants utilize circulating fluidized bed (CFB) combustion and inject limestone to control SO2 emissions, the incremental costs for controlling SO2 by adding a scrubber (wet or dry) is higher than what is projected. In many cases, the CFB unit cannot simply add more limestone to obtain 95% to 98% reduction in SO2. There are limitations to what the boiler can be fed or hold. The additional limestone means additional fuel with more sulfur going to the boiler and increased uncontrolled NOx emissions. The increased uncontrolled NOx means an increase in ammonia usage for SNCR units. However, the amount of ammonia that can be utilized is limited by permitted levels of ammonia slip (5ppms). Therefore, all of these issues need to be considered when evaluating actual unit operation and equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-2751.1 p.9]
Dow Chemical Company
Dow believes that EPA's allocation of NOx allowances under the Transport Rule/FIP is flawed. If it is determined that a FIP is still authorized and needed after consideration of the comments above and the more detailed comments submitted by LCA, Dow requests that EPA substantially revise its methodology for allocations and the allocations themselves. EPA's scheme causes an economic inequity, for no discernable environmental reasons. EPA has refused to allocate any allowances to quite a number of sources in Louisiana simply because EPA's IPM modeling projects that they will no longer be operating or will be operating at only minimal or reduced rates.1 This means, if they are actually operating, they will have to purchase potentially millions of dollars per year worth of NOx allowances. While the economic model EPA used is not well understood, the reality is that the proposed allocations do not align with the very data submitted to EPA CAMD for the units under CAIR. [EPA-HQ-OAR-2009-0491-2775.1 p.3]
Dow is the owner and operator of the Plaquemine Cogeneration facility which is subject to Acid Rain requirements for SO2 and CAIR requirements for NOx. The Plaquemine Cogeneration facility consists of four gas-fired GE Frame 7 FA gas turbines which are equipped with dry low NOx combustors. Each turbine is equipped with a heat recovery steam generator (HRSG) and a supplemental-fired duct burner system. Each gas turbine/duct burner unit is equipped with a Selective Catalytic Reduction (SCR) unit for further NOx reduction. Thus these units employ Best Available Control Technology.  [EPA-HQ-OAR-2009-0491-2775.1 p.3]
The Dow Plaquemine Cogeneration facility provides critical steam and electricity to the Dow Louisiana Operations chemical manufacturing facilities. Excess electricity is sold to the grid. Each of these EGUs runs year round, not simply during ozone season. These units represent a considerable investment to Dow. These units operate a high percentage of their capacity and Dow has no plans whatsoever to curtail operations. [EPA-HQ-OAR-2009-0491-2775.1 p.3]
It is difficult to understand, given the above, that EPA would project that the Dow Plaquemine Cogeneration facility would operate at reduced rates. EPA sent no data requests to Dow asking about future operations of the Plaquemine Cogeneration units. EPA CAMD has a considerable amount of historical data indicating the units operating rates and emissions, yet the IPM projects that these units will be operating at reduced rates in eighteen months. For this reason alone, note due to any environmental impact, EPA has proposed to provide each of the Dow units with allowances covering only a portion of their annual NOx emissions. The below table demonstrates this point: [EPA-HQ-OAR-2009-0491-2775.1 p.3]
[[Data Table Here]]
The assumptions EPA used to reach this result must be modified to reflect reality. The adverse impact to Dow associated with the cost of purchasing NOx allocations would be significant. The staff for the Louisiana Public Service Commission has estimated at least the following annual costs to Dow (i.e., not including ozone season allowances) to be $159,768. This estimate was based on a conservative assumption that annual NOx allowances would be valued at $1,200 per ton. With such a limited trading market as proposed by EPA, the adverse economic impact could be much higher. The Dow Plaquemine Cogeneration units are highly efficient, low emitting cogeneration units. EPA has no rational reason for imposing such costs on these units.  [EPA-HQ-OAR-2009-0491-2775.1 p.5]
If Interstate Transport impacts from Louisiana need to be addressed, EPA should allow Louisiana to make the required NOx and SO2 allocations in a SIP. Alternatively, in the event a FIP is needed and justified to address interstate transport of Louisiana emissions on Texas receptors, then Dow requests that EPA allocate the NOx allowances by providing EGUs with the same % of the total state budget that were approved in the Louisiana NOx CAIR SIP. [EPA-HQ-OAR-2009-0491-2775.1 p.5]
DTE Energy
DTE supports EPA's proposal not to permit government-run allowance auctioning under the preferred remedy option. EPA should remain opposed to allowance auctioning under the preferred option or the intrastate trading alternative. [EPA-HQ-OAR-2009-0491-2851.1, p.3]
Duke Energy
Duke Energy Supports EPA's Proposal to Permit Banking of Allowances Beginning in the First Year of the Program.  In the PTR, EPA properly recognizes the important environmental and economic benefits of allowance banking. The ability of sources to use banked allowances for compliance with the program encourages them to make early emission reductions to the extent that cost-effective early reductions are possible. While the nature and stringency of the PTR's emission reduction requirements and its proposed compliance schedule make the extent to which it might be possible for sources to make extra emission reductions highly uncertain, nevertheless, having the option of being able to make extra reductions and bank allowances is an important flexibility measure that EPA should retain. [EPA-HQ-OAR-2009-0491-2689.1, p.3]
Duke Energy Supports EPA's Decision Not to Auction Allowances under the Proposed Limited Trading Remedy Option.
Duke Energy supports EPA's proposal not to include any allowance auctioning under its Proposed Limited Interstate Trading Remedy Option. The only outcome of an allowance auction is an increase the cost of the program for companies and their customers. An auction would make no contribution toward achieving emission reductions or the environmental objectives of the program. If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that Duke Energy does not support, EPA should remove from that option the proposed provisions for allowance auctions. It is entirely possible to accomplish the objectives of those proposed auctions through a no-cost distribution of allowances. [EPA-HQ-OAR-2009-0491-2689.1, p.5]
Duke Energy Supports EPA's Proposal to Continue to Allocate Allowances to Non-Operating Units for a Limited Period of Time.
In the PTR, EPA proposes that once an electric generating unit ("EGU") does not operate (i.e., does not combust any fuel) for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation, and beginning with the seventh year, all allowances that would otherwise have been allocated to the unit would be allocated to the new unit set-aside for the state in which the non-operating unit is located. Duke Energy supports this approach.4 Duke Energy agrees with EPA that this will reduce the incentive to keep marginal units operating, and it strikes a reasonable middle ground between the options of immediately stopping allocations for non-operating units and continuing to provide allowances to non-operating units for an unlimited period of time.
Duke Energy Recommends Using Heat Input to Allocate State Budgets to Individual Units.
EPA asks for comment on alternatives to its proposed method of allocating allowances to individual units based on adjusted reported or adjusted projected emissions. EPA specifically asks for comment on an alternative method for allocating allowances to individual units based on projected heat input. Duke Energy believes that allocating allowances equal to each state's budget based on each source's pro rata share of total state heat input is a better way of distributing allowances than EPA's proposed method and Duke Energy supports EPA's use of a heat input-based allocation approach.  [EPA-HQ-OAR-2009-0491-2689.1, pp.17-18]