44. Transport Rule, 75 Fed. Reg. at 45,370 (Heat input means, with regard to a unit for a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.); ENERGY INFO. ADMIN., DEP'T OF ENERGY, REPORT NO. SR-OIAF/2004-05, ANALYSIS OF S.1844, THE CLEAR SKIES ACT OF 2003; S.843, THE CLEAN AIR PLANNING ACT OF 2003; AND S.366, THE CLEAN POWER ACT 2003 (2004) http://www.eia.doe.gov/oiaf/servicerpt/csa/background.html (last visited Sept. 30, 2010) ("[H]istorical heat input . . . allocation is based on historical fuel use."). [EPA-HQ-OAR-2009-0491-2648.1, p.8]
53. The Transport Rule defines "total energy output" as "the sum of useful power and useful thermal energy produced by the unit." Id. at 45,371. The Transport Rule also defines "gross electrical output," which means "electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls)." Id. at 45,370. In order to encourage efficient energy generation, energy output must be measured after internal uses of that electricity. A plant is not efficient if it uses significant amounts of its electricity internally. Measuring electricity output before internal uses would count the inefficient internal uses toward the plant's allowance allocation, thereby negating the efficiency-encouraging aspects of energy output based allocation. [EPA-HQ-OAR-2009-0491-2648.1, p.11]
54. The Massachusetts NOx Allowance Trading Program uses a similar method that allocates allowances based on "a unit's net electric output in MWh." 310 MASS. CODE REGS. 7.28(6)(d)(1). [EPA-HQ-OAR-2009-0491-2648.1, p.11]
Rochester Public Utilities (RPU)
RPU is not able to specifically comment on the calculations that EPA used to determine the allocations as there was insufficient time to review all of information provided, and further the methodology was not fully explained. RPU will, however, provide the following comments on some of the supporting information used by EPA to establish a baseline for the allocation. [EPA-HQ-OAR-2009-0491-2802.1,p.2]
It is our understanding that EPA used operating data for Quarters 1  -  3 of 2009 and Quarter 4 of 2008, as listed in Table 1, to determine unit-level allowance allocations for Unit 4. This time period is not representative of Silver Lake Unit 4's normal operation. During this time, Unit 4's average operation was less than 500 hours and 150,000 million Btu (mmBtu) heat input per quarter. Typical operation of this unit is closer to 1,300 hours and 510,000 mmBtu heat input per quarter. Table 2 provides a summary of the average operating data of each quarter for the period between 2003 and 2008. A comparison of the data presented in Tables 1 and 2 clearly indicates that the operational data used in the development of the proposed Transport Rule was not representative of routine operation for Silver Lake Unit 4. [EPA-HQ-OAR-2009-0491-2802.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2802.1, p.3 for Tables 1 & 2.]]
The abnormally low operation of Unit 4 during the time period used by EPA is attributable to the installation of the new AQCS, milder weather and the economic downturn which affected the U.S. Energy Market1, especially in the midwest. As a participant of the Midwest Independent Transmission System Operators (MISO) market, RPU's dispatch of Silver Lake Unit 4 for operation is primarily related to electrical demand in the MISO region and local transmission and generation constraints. The quarters chosen by EPA should not be considered appropriate quarters for the following reasons:  [EPA-HQ-OAR-2009-0491-2802.1, pp.3-4]
:: 4th Quarter 2008: Silver Lake Unit 4 was in a 6 week outage to interconnect the new AQCS. This outage began in October 2008 and ended in December 2008.
:: 1st Quarter of 2009: Though some operation for electrical demand did occur, tuning and testing of the SDA and PJFF occurred during this quarter.
:: 2nd Quarter of 2009: Unit 4 was not operational in part due to economic factors and installation of additional urea injection ports for the SNCR. There were only three hours in which the boiler was operated, solely for maintenance purposes and not electrical generation.
:: 3rd Quarter of 2009, Unit 4 was dispatched on a very limited basis due to the economic recession, and a good portion of the time the unit did operate was for the final tuning and testing of the SNCR.  [EPA-HQ-OAR-2009-0491-2802.1,p.4]
RPU requests that EPA repeat the procedures used to determine unit-level allocations using historical data that are more representative of Unit 4's typical operation. Table 3 provides an appropriate range of operating quarters that stays within the range of data sets laid out in the Transport Rule. [EPA-HQ-OAR-2009-0491-2802.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2802.1, p.4 for Table 3.]]
RPU further requests that EPA use the 2007 quarter 4 heat input in any calculations or modeling instead of the incomplete 2008 quarter 4 heat input for the reasons provided above. Attachment A provides a copy of the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool Emissions Summary Report for Silver Lake Unit 4 for 2003  -  2009. [EPA-HQ-OAR-2009-0491-2802.1,p.4]

1. The U.S. Energy Information Administration's Annual Energy Outlook (AEO) for 2009 and 2010 reported a drop in total electricity generation of 1% in 2008 and 3% in 2009. The 2010 AEO further stated that "Although other factors, including weather, contributed to the decrease, it was the first time in the 60-year data series maintained by the EIA that electricity use fell in two consecutive years." But this is the time period EPA chose to use for their base case of actual data from annual emissions data starting in the most recent non-null first quarter, second quarter, third quarter, and fourth quarter emissions and heat input, between quarter 1 2007 and quarter 3 2009. A more appropriate time period to reflect normal operation should have started in 2007 or should have been an average of a period over several years.
San Miguel Electric Cooperative, Inc.
The proposed CATR outlines allocation to existing units (75FR45309), " EPA proposes that ...each existing unit in a given state receives allowances commensurate with the unit's emission reflected in whichever total emissions is lower for the state, 2009 emissions or 2012 base case emissions projections."  [EPA-HQ-OAR-2009-0491-2641.1, p.4]
The EPA proposed allowance allocation methodology radically departs from previous regulatory allocation methods and creates numerous inequities and other poor policies without justifications. The proposed allocation method is based on EPA computer model projections of both future individual unit utilization and emission reduction capabilities at specified marginal cost of emission reduction levels. The model attempts to predict the future of literally thousands of electric utility fossil fuel units located within the proposed CATR trading areas. Regardless of the purported sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. Case in point is the numerous errors, outlined above, of the San Miguel generating unit. It is not likely that the San Miguel unit is the only unit where errors have occurred. [EPA-HQ-OAR-2009-0491-2641.1,p.4]
The model also cannot account for future business decisions, the necessity of which is not yet presently known or anticipated but nonetheless may need to be made that would significantly affect an individual unit's utilization within the utility system. There are literally dozens of significant factors that affect future unit utilization of which the model does not and cannot take into account. [EPA-HQ-OAR-2009-0491-2641.1,p.4]
San Miguel believes most of the problems inherent in the proposal's methodology could be resolved if state budgeted allowances were distributed to each unit within the state based pro-rata on the unit's portion of the state historic heat rate updated periodically to include new units. Such distribution should sub-categorize between coal, gas, and oil. The allocation methodology could be structured in a manner similar to that contained in Clean Air Interstate Rule (CAIR) for annual NOx allocations as a SIP for all the CATR trading programs. Specifically, the salient features of this methodology include allocating allowances to existing units based on historic heat input using the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set-aside and folding new units into existing unit category after five years of operation. As with the CAIR approach, this methodology could provide options for each state to consider whether new units should receive allowances from a set-aside during their initial year of operation and if retired units should continue to receive allowances, and if so how long or at a diminished allocation.  [EPA-HQ-OAR-2009-0491-2641.1, pp.4-5]
San Miguel encourages the EPA to revise the methodology for unit allocations from the proposed method to a historically based system similar to the CAIR proposal. [EPA-HQ-OAR-2009-0491-2641.1, p.5]
 The preferred remedy option allowing unlimited emissions trading during the initial 2012 compliance period and limited interstate trading in the second compliance period recognizes the economic benefits of trading and should be retained. The auctioning of allowances would drive up program compliance costs. Therefore, it is justifiably excluded from the preferred remedy and proposed intrastate option.   [EPA-HQ-OAR-2009-0491-2641.1, p.6][[This comment can also be found in Outline Heading V.D.3.a.]]
Seminole Electric Cooperative Inc.
IPM Prediction. Despite several phone calls to EPA's 'experts' on IPM modeling, neither EPA's experts nor Seminole can understand exactly what erroneous assumptions EPA is making to produce this fundamentally-flawed result. We can see the data going into the model, and we can see the results coming out, but it is apparently not possible to track a specific unit through the IPM model. EPA's use of a modeling platform that cannot explain how and why it arrived at a specific conclusion for a specific unit, and then EPA's reliance on that conclusion in establishing permanent compliance obligations, is an egregious abuse of discretion/power and a hallmark of an arbitrary and capricious rule. [EPA-HQ-OAR-2009-0491-2632.1, p.4]
According to EPA representatives, the three most likely variables affecting IPM's allocation to a specific unit are annual utilization of the unit (i.e., heat input), sulfur content of the fuel (i.e., percent by weight per ton of coal or lb/mmBtu inlet to the FGD), and removal efficiency of the FGD system (i.e., percent difference between the inlet and outlet of the FGD). In looking at the EPA projections, the heat input and removal efficiency appear to be within the ranges of reasonably representative values (although the projected FGD removal efficiency of 92.7 percent is on the high end of the range). This leaves the sulfur content of the fuel as the remaining variable primarily responsible for the unachievable allocation. As stated above, the sulfur content of Seminole's coal supply is approximately 3 percent by weight, with authority to co-fire up to 30 percent petcoke (which can be up to 7 percent sulfur by weight). In 2009, without burning any petcoke, Seminole's inlet-to-the-FGD sulfur content averaged approximately 4.7 lb/mmBtu; EPA's projected 2012 inlet is 1.4lb/mmBtu. To reach EPA's projection, Seminole would have to reduce the sulfur content of its fuel by over 70 percent. [EPA-HQ-OAR-2009-0491-2632.1, p.4]
Apparently, IPM predicted that Seminole (and according to EPA representatives, many other eastern coal-fired units) would immediately switch to coal from the Powder River Basin (PRB) in the western U.S. to achieve this level of reduction. [EPA-HQ-OAR-2009-0491-2632.1, p.4]
Technical, Practical and Economic Infeasibility of the IPM Prediction. Switching to lower sulfur coal, such as from PRB, would have substantial technical, practical and economic consequences, if it could be done at all. First, from a technical perspective, coal-fired boilers are designed for the fuel that it will burn, with special consideration of heat, sulfur and ash content. PRB coal, for example, has significantly lower heat content than eastern bituminous, requiring a corresponding increase of approximately 35 percent in the volumetric consumption required to generate the same/needed load. And there is a technical/physical limit on the quantity of coal that can be burned in the units, meaning that using a lower heat content coal would effectively de-rate the unit, requiring additional generation elsewhere to make up the loss. [EPA-HQ-OAR-2009-0491-2632.1, pp.4-5]
Lower sulfur western coals can also release heat in different locations than the boiler was designed for, resulting in increased tube failures and unit downtime. PRB coals also contain more volatiles, which increases the risk of explosions when the hot mill is shutdown and then restarted. Plants burning higher sulfur coals do not have the specially-designed mills to compensate for this increased risk. We estimate that a minimum of 20 months would be needed to design, fabricate, transport and install such special mills. Seminole's brand-new SCRs and existing ESP systems could also be materially impacted due to differences in ash contents of the different sulfur fuels. SCRs are impacted with differing ash contents that can have different mineral contents that can poison the catalyst, significantly shortening catalyst life. ESP performance is also impacted due to differences in resistivity and S03 rates. Correcting the resulting increased particulate emissions from the stack would require redesigning and substantially increasing the size of the ESP. Ash handling equipment and ash storage facilities would need to be expanded if the ash content is greater. And since no additional ash storage is available, any increase would have to be sent offsite. Finally, material handling and processing would increase due to lower heat content (and higher volume) of lower sulfur coal, possibly requiring additional equipment and increased fugitive emissions.  [EPA-HQ-OAR-2009-0491-2632.1, p.5]
Practically, EPA has not been able to explain how the existing PRB coal production and railroad transportation capacity can accommodate the exponential increase in the availability of western coals to all of the eastern units that IPM projects will/must switch. For starters, Seminole understands that there are considerable bottlenecks in the rail lines that cross the Mississippi River and are routed through the Southeast U.S. Any expansion of the use of PRB coals in the east will also require substantial expansion, development and permitting for new mines in the PRB, as well as a major expansion of all railroads capable of moving coal from the PRB to the east. This expansion will not happen overnight and could take a decade or more to become reality, assuming the states and environmental communities support such an expansion of PRB coal mining and related transportation networks through their backyards. [EPA-HQ-OAR-2009-0491-2632.1,p.5]
Economically, there will be a dramatic impact on Seminole if it was even possible for it to switch to western lower sulfur coals. In addition to the equipment costs above, Seminole would have to breach existing long-term contracts. In 2005, Seminole determined that switching to PRB coal would cost between $40,000,000 and $66,000,000 per year due to the higher price of this coal, increased transportation costs, and lower heating value of the coal. And this annual figure does not include de-rating the unit and the need for replacement power. If many other eastern companies are required to now switch as well, this cost would be expected to be dramatically higher. [EPA-HQ-OAR-2009-0491-2632.1, pp.5-6]
Accordingly, numerous questions must be answered to understand whether IPM's projection bears any resemblance to reality. What is the precise increase in the volume of coal that EPA expects will be transported from the west to the east as a result of the proposed rule? Will additional rail lines or routes be needed? What is the proposal's economic impact on the rail business? How will the massive fuel switch affect the national economic outlook for the U.S. for energy and GNP? How will it affect the cost of coal, in the short term and long term? How much lower sulfur coal is available in the west? And how long will this last, given EPA's projection of fuel switching? [EPA-HQ-OAR-2009-0491-2632.1, p.6]
Southern Company
XIII. EPA's State Budget and Unit Allocation Methodologies Are Fundamentally Flawed
To establish state budgets and unit allocations, EPA used a combination of reported data and projected data, both adjusted for controls. As mentioned earlier, EPA's methodology was not clearly defined and Southern Company spent  countless hours replicating EPA's approach. However, Southern Company has identified a number of fundamental flaws in EPA's methodologies for developing and adjusting this data for purposes of setting the state budgets and unit allocations. These flaws are described below. [EPA-HQ-OAR-2009-0491-2864.1, p. 48]
A. 2009 Was Not an 'Average Year'
To develop the reported emissions data for purposes of setting state budgets and unit allocations EPA took the most recent 'non-null' quarterly data (through the third quarter of 2009) for each quarter (quarter one through four). In most cases, this meant using data from the fourth quarter of 2008 through the third quarter of 2009 as a representative year (or 2009 ozone season data as a representative ozone season). This process is significantly flawed. EPA repeatedly claims that state budgets are based on emissions from an 'average year.' Yet its methods accomplish nothing of the sort. Put simply, EPA's selected representative year is anything but average. [EPA-HQ-OAR-2009-0491-2864.1, p. 48]
From 2008 through 2009, the nation was in the middle of the most significant economic downturn since the great depression. Electricity demand and heat input were unusually low. EPA appears to recognize this anomaly by adjusting reported NOx data based on 2008 heat input.4 But even that adjustment does not fully account for the unusually low demand for electricity beginning in the second half of 2008. In addition, in 2009 natural gas prices were at extraordinarily low resulting in highly unusual dispatch of the fossil fuel fired electric generating fleet. In some cases, large coal-fired units were idled while natural gas fired units - normally reserved for peaking power - ran at much higher capacity factors. Due to the combined forces of (i) decreased demand and (ii) low natural gas prices, 2009 is perhaps the least representative year in decades for determining average annual emissions. EPA should fully account for the economic downturn by selecting reporting years that were not impacted by the economic downturn. [EPA-HQ-OAR-2009-0491-2864.1, pp. 48-49]
Instead of attempting to select a single representative year, consistent with past practice, EPA should use a longer average period of time to develop reported emissions data. By selecting a longer period of time (e.g., three years as used in the Acid Rain Program, the NOx SIP Call and CAIR), EPA would capture data that is more representative. Selecting the three year period from 2005 to 2007 would fully account for the economic downturn, capture two full operational cycles for a typical unit, and would provide much more reliable data. [EPA-HQ-OAR-2009-0491-2864.1, p. 49]
[The above comments can also be found at section IV.E. of the comment summary.]
C. EPA Should Allow States To Develop Allocations
EPA should allow states to develop state-specific allocations through the SIP process. States were very successful in dividing allocations for CAIR and the NOx SIP Call and are better suited to developing fair and consistent allocations that take into consideration unique aspects of EGUs (e.g., fuel mixes or anticipated new unit construction) in the state. States are most familiar with the types of EGUs in their states and can best determine how allocations should be made. [EPA-HQ-OAR-2009-0491-2864.1, pp. 49-50]
D. EPA Should Reward, Not Penalize, Units for Early Reductions
EPA's methodology for distributing allocations based on unit-by-unit analysis unfairly penalizes sources that installed controls before 2010 (e.g., Miller 3 & 4 FGD, Miller 1, 2, 3 & 4 SCR, Gorgas 8, 9, and 10 FGD, Gorgas 10 SCR, Gaston 5 SCR). Allowances should be allocated to sources based on a universal methodology. Additionally sources that have been burning low sulfur coals, establishing a lower base of S02 emissions will be unfairly penalized under the current allocation methodology. Unfairly distributing allocations negates the value of a market based program. [EPA-HQ-OAR-2009-0491-2864.1, p. 50]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to allow banking of allowances. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to allow retired units to continue to receive allowances for some time. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
A. EPA's Decision to Allow Interstate Trading, Although EPA Should Have Allowed More EPA's Proposed Remedy Option allows limited interstate allowance trading, while its two alternative options would not allow any interstate trading. Southern Company supports EPA's proposal to permit at least some degree of allowance trading, although as discussed elsewhere, EPA should have considered more trading. Permitting interstate allowance trading would provide for increased flexibility and permit more cost-effective compliance options. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
EPA's Decision to Not Establish Allowance Auctions in the Preferred Approach, Southern Company supports EPA's proposal 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. [EPA-HQ-OAR-2009-0491-2864.1, p. 53]
B. EPA's Decision to Allow Allowance Banking
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, a feature of CAIR that was not challenged in the litigation on that rule and that the court's opinion in no way undermines. 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. Unfortunately, the nature and stringency of the proposed rule's emission reduction requirements and its proposed compliance schedule would make it very difficult for most sources to make extra emission reductions during the early years of the program. Permitting allowance banking in conjunction with an adjustment to the compliance schedule that would allow sources adequate time to comply with the program (and give states adequate time to develop SIPs) could well result in greater amounts of early emission reductions and, most likely, greater emission reductions over the long run. [EPA-HQ-OAR-2009-0491-2864.1, pp. 52-53]
E. EPA's Decision to Allow Retired Units to Continue to Receive Allowances for Some Time
EPA requests comment on its proposal to continue to allocate allowances to non-operating units. 54 We support EPA's proposal to continue allocations to non-operating units but believe that the allocations should be perpetual, as they are under Title IV. Perpetual allocations encourage retirement of less efficient units, and, as EPA notes, discourages operators from continuing to operate older units 'simply to avoid losing the allowance allocations for those units.' EPA's proposal still promotes continued operation of older less efficient units because each year of operation continues the unit's allocation by an additional year. FU11her, unit owners will be much more likely to retire units if they have control over the allowances perpetually and could plan on the allocations for both existing and new units or choose to sell the allowances to other entities for their new units. In short, perpetual allocations make planning easier, provides more certainty and best encourages retirement of older units.[EPA-HQ-OAR-2009-0491-2864.1, p. 53]
Southern IL Power Cooperative
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 essentially permanent unit allocations comes from EPA's computerized virtual world containing numerous false assumptions. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
The proposal does solicit comment for alternative approaches, and in particular an approach based on Heat Input, p. 45311. We suggest 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. As this alternative is detailed somewhat in the proposal, allowances could be distributed based state allowance budgets pro rata based on unit historic heat rates. 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. This Heat Input approach would eliminate perpetual allocations to most polluting units, reward consumers who purchase power from new clean sources, and overall demonstrate a rational policy. This method would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
As proposed, unused CAIR allowances would be eliminated as a means of compliance beginning in 2012. For new units, a 3% set aside of CATR state allowance budgets shared pro rata in event of over demand, and no allocation during initial year of start- up provide no assurance that necessary allowances would be available for new units necessarily utilizing best emissions control technologies. EPA has stated that it wholly supports new cleaner fossil fuel generation. Yet this policy would function in opposite of encouraging the newer, cleaner generation. EPA should incorporate unused CAIR allowances into the CATR program and make available to new units to the extent that CATR allowances are not available from the 3% CATR new unit set-side. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
As proposed, unused CAIR allowances would be eliminated as a means of compliance beginning in 2012. For new units, a 3% set aside of CATR state allowance budgets shared pro rata in event of over demand, and no allocation during initial year of start- up provide no assurance that necessary allowances would be available for new units necessarily utilizing best emissions control technologies. EPA has stated that it wholly supports new cleaner fossil fuel generation. Yet this policy would function in opposite of encouraging the newer, cleaner generation. EPA should incorporate unused CAIR allowances into the CATR program and make available to new units to the extent that CATR allowances are not available from the 3% CATR new unit set-side. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
State of Delaware Department of Natural Resources & Environmental Control
Allowance Distribution Methodology. In the EPA's proposed rule and supporting technical support documents, EPA proposes an allowance distribution methodology for distributing allowances to individual units. The proposed unit-specific allowance allocations will be made on the basis of each unit receiving its proportional share of its state budget based on that unit's share of state emissions assumed in developing the budget. Using this methodology, the units that historically had the highest emissions (in percentage of the state's total) would be allocated that same percentage of the states allocation. It appears that such a methodology provides a negative benefit to those units that either had a lower emission rate by design or installed controls to achieve a lower emission rate in the past. It is Delaware's opinion that it would be more appropriate to allocate allowances on the basis of a specific unit's historic heat input, as a percentage of the entire heat input that resulted in the state's total allowance allocation. It is Delaware's opinion that this would establish a fuel-neutral allocation methodology that does not provide a negative benefit to those units that had previous reduced their emission rates. [EPA-HQ-OAR-2009-0491-2980.1, p.8]
State of Louisiana, Department of Environmental Quality
ALLOCATIONS/ALLOWANCES
Comment: EPA's inappropriate use of the IPM model to make short-term decisions about which units are slated for retirement does not account for real world truths about future use of gas-fired units within Louisiana. EPA should gather additional real-world information regarding must-run units and local grid constraints to update the expected conditions before finalizing this rule. [EPA-HQ-OAR-2009-0491-2655.1, p.4]
LDEQ must first reiterate its belief that the allocations are best handled in-state. Confirming this belief are the transport rule 2012 NOx allocations; the allocations represented in the Transport Rule differ greatly from the CAiR 2012 allocations as demonstrated in the attached table. (See Attachment C) [See EPA-HQ-OAR-2009-0491-2655.1, p.25 for Attachment C] Some sources are allocated significantly more NOx emissions than they require while other sources currently in operation are allocated absolutely no NOx emissions. Historically, the units that received insufficient or no allocations under the Transport Rule have operated in the past and are operational at the present time. There are no signs from industry to indicate that these units will be retired in the foreseeable future. [EPA-HQ-OAR-2009-0491-2655.1, p.4]
There are also issues of grid electrical constraints within our state which necessitate the operation of some older less efficient units. We believe that other commenters, such as the Louisiana Public Service Commission, have provided additional input on this issue. Based on the IPM model economic input data, natural gas-fired boilers will no longer be online and are therefore not included in the allocation scheme presented in the proposed transport rule. Louisiana holds that this is not accurate, as many of the electric generation facilities in this state, as well as those in Mississippi and Texas, use this type of generation. If these facilities are discounted due to the economic indicators of the IPM model and allowances are not provided to them, the citizens of Louisiana will face large rate increases as these facilities will have to purchase allowances in order to operate and provide power. [EPA-HQ-OAR-2009-0491-2655.1, pp.4-5]
Further, the permitting of these types of facilities usually includes an alternate fuel for operation, namely fuel oil. It is evident that this fuel type was not included in the IPM model; if this fuel type had been included, allowances would have been awarded to the facilities that have otherwise been excluded. Several cogeneration units that should be exempt from the transport rule were given allocations. These units are exempt under CAIR and under the proposed transport rule because they have not sold the greater of 1/3rd of their potential electrical output or 219,000 MWe to the grid in any calendar year since 1990 or the year of first fire, whichever is later. These units include: [EPA-HQ-OAR-2009-0491-2655.1, p.5]
A. Dow St. Charles Operations
B. Evangeline Power Station
C. Formosa Plastics
D. PPG Powerhouse C
E. Shell Chemical
F. Georgia-Gulf [EPA-HQ-OAR-2009-0491-2655.1, p.5]
Comment: LDEQ and other stakeholders should have the opportunity to review EPA's final rule prior to publication to make certain that the information provided and the future modeling runs that will be made will actually address the problems outlined in this proposal. Additionally, EPA should ensure that adequate consideration of comments received through the Notice of Data Availability is factored into the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2655.1, p.6]
LDEQ has participated in a number of conference calls between EPA and both regional and national state air quality management organizations since the proposed rule was issued. During those calls it has become evident that EPA must address emissions inventory discrepancies as well as economic inputs before it can produce final IPM modeling runs to achieve meaningful results and final S02 and NOx allocations. State air quality agencies like LDEQ should have the opportunity to review this information before EPA goes final with this rulemaking. LDEQ strongly believes that allowing the state's input may deter allowance gaps as well as potential litigation, thus effecting a timelier implementation of the rule. [EPA-HQ-OAR-2009-0491-2655.1, p.6]
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA disagrees with the use of the Integrated Planning Model (IPM) for allocating unit level emissions. U.S. EPA should' provide for unit level allocations to be the responsibility of the states as part of a State Implementation Plan (SIP) process. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
Ohio EPA has concerns with respect to the new~ource set aside and the treatment of shutdown units. U.S. EPA must provide a framework that allows for adequate and necessary growth in order to ensure electric reliability is maintained. [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
a. The new unit set aside, 3%, is taken off the top of what is already a very restrictive S02 budget. [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
b. Ohio EPA questions if a 3% new unit set aside is enough, especially given the approach for handling shutdown provisions.
Units that are permanently shut down would continue to collect allowances (theoretically for use by another unit at the facility or trading) for six years. Then, those allowances would go into the new unit set aside in the seventh year. Ohio EPA understands U.S. EPA's intention of limiting the likelihood of owners continuing to operate older units just to receive allowances. However, Ohio EPA has concerns that not distributing these allocations to the new unit set aside sooner, given the small new unit set aside allocation of 3%, may create reliability issues for the new, more efficient units. Given that allocations are based on a low demand year (discussed later), the variability limits are restrictive, and the new unit set aside is restrictive, owners may need to wait years before allocations are available for new units due from the shutdown of existing units. [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
Further, U.S. EPA states in the proposal that the analysis used to determine the appropriate size of a new unit set aside assumed that allocations for non-operating units 'would be allocated to the new unit set aside after a unit had ceased operating for three consecutive years.' [75 FR 45310] It is not clear from the documentation whether the analysis considered those allocations to be available in the fourth year or seventh year. It is unclear if the analysis (which seems to allude to availability of allocations in the fourth year) is consistent with the outcome included in the proposal (availability of allocations in the seventh year). [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
c. Ohio EPA is very concerned with the schedule for determining if sufficient allocations are available for all new units and for recording new unit allocations. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
In the proposal, U;S. EPA discusses how, if the new unit set aside does not contain sufficient allocations for all new units, then the allocation to all new units would be proportionally reduced. Further, for new units, allocations are not recorded until September of the year in which they are needed. This could in turn inhibit newer, more modern units from operating due to the uncertainty associated with the availability of allocations needed for the new unit and because of the lag between the new unit set aside account being populated when a unit shuts down. Ohio EPA believes it is completely unacceptable that U.S. EPA provides no assurance that the owner of a new unit will have sufficient allocations until nine months into the control year that they are needed. Further, there is no mechanism in this proposal for a new unit to become an existing unit. Over time, as more and more existing units retire and more and more new, more efficient units enter the program, they will be subject to new unit procedures and restrictions that are unreasonable. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
d. Ohio EPA is concerned the proposed rule will put newer, more efficient units at greater risk of noncompliance than existing units. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
While it may be assumed that owners with allowances being distributed for shut down units will be able to trade during their six year allowance allocation period to allow for new unit growth, this is not clear in the proposal. For example, what would happen to a new unit that is not able to purchase allocations from a shutdown unit and did not receive allocations, or enough allocations, from the new unit set aside? If the assurance provisions for the state were triggered, this company would be severely penalized for being over its allocation plus the variability limit when, in fact, it was just not able to receive sufficient allocations due to the restrictive new unit set aside account and the time lag between, populating that account from shut down units. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
e. Ohio EPA is concerned U.S. EPA has not adequately considered all variables that may affect the amount of allocations a new unit receives. Allocations are based on actual emissions during the first year (control period) of operation of a new unit. In other words, the first year's actual emissions determines future allocations. This raises many questions that are not addressed in the proposal. What will occur during the first year are new unit emissions not addressed or considered under the program in any manner? What if a unit doesn't begin operating at the beginning of the control period - will future allocations be based on only a partial year of operation? When this is re-calculated, based on actual emissions annually thereafter, what assurance is there that owners will not maximize emissions when there is incentive to obtain a greater portion of the new unit set aside? Appropriate flexibility and safeguards are needed. [EPA-HQ-OAR-2009-0491-2793.2, pp. 5-6]
6. Ohio EPA has concerns regarding the ramifications of inhibiting the limited trading program. U.S. EPA must provide a framework that provides assurances that allocations can be traded rather than forcing owners to retain excess allocations out of fear of a future short fall. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
a. Ohio EPA is very concerned that the insufficient allocations of S02, the restrictive variability limits, and limited trading scheme for Group 1 S02 states, in conjunction with the issues and questions raised regarding the new unit set aside, will inhibit trading. In fact, there are owners in the state that have installed state of the art NOx controls on some units, but nevertheless have NOx emissions greater than the proposed allocations. Due to the nature of the proposed program design, U.S. EPA cannot assume that wide-spread trading will occur to 'make up' for t~e short fall in allocations for certain units. With such insufficient allocations, if any allocations are left at the end of the year sources will likely bank for future years rather than trade due to the significant repercussions that occur when assurance provisions are triggered. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
Ohio EPA has concerns regarding the methodology to determine allocation budgets based on actual emissions. U.S. EPA must use appropriate years representative of normal operation when calculating allocations based upon actual emissions. [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
a. Ohio EPA is concerned with what appears to be an arbitrary decision; using quarter 4 of 2008 and quarters 1, 2 and 3 of 2009 to establish 2012 budgets - both of which were low demand years. Nevertheless, U.S. EPA appears to believe that this time period accurately represents normal emissions from these sources. U.S. EPA should recognize that the nation, and particularly the Midwest, was in a severe economic downturn during 2008 and 2009. [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
b. Ohio's budget, and unit specific allocations, are being established based on a specific period of time, a time of economic crisis, without any future adjustments being considered to those base budgets taking into account improvement in the economy, and therefore, demand. The variability limits are not sufficient to make up for the use of severely low demand years when calculating base budgets. In addition, some units were not operating for some or all of this· period in order to install controls to address CAIR. It appears from the technical support documents that U.S. EPA intended to substitute other quarters in the calculations when emissions were zero; however, if emissions were drastically under previous quarter's emissions (e.g., a unit may have operated for only a small part of a quarter) there was no such adjustment. In many cases, units are allocated budgets for 2012 and 2013 ba~ed on the assumption that demand will be as low as it was in 2008 and 2009. Such units may be forced to be underutilized if demand does improve. [EPA-HQ-OAR-2009-0491-2793.2, pp. 8-9]
State of Wisconsin, Department of Natural Resources
Once emission budgets are set, EPA should consider default alternative mechanisms within the FIP for allowing states to distribute allowances, such as providing the simple formulas for distribution of allowances within a trading program. Wisconsin disagrees with solely relying on the Integrated Planning Model (IPM). [EPA-HQ-OAR-2009-0491-2829.2, p.2]
EPA needs to primarily depend on air quality results instead of control costs in defining EGU responsibility to remedy significant contribution and to set final emission budgets.
State final emission budgets (2014) need to be set with a stronger linkage to residual air quality impact from the EGU on downwind sites compared to the current proposed linkage of limiting emission reductions by an arbitrarily low cost threshold. EPA has set which states have contribution reduction responsibility based on air quality impact, but appears to default to a modeling of the most efficient regional EGU control program based exclusively on cost-effectiveness. [EPA-HQ-OAR-2009-0491-2829.2, p.7]
In defining significant contribution, EPA should place a greater emphasis on air quality impact (contribution) remedy than the assessed state-by-state marginal control cost-effectiveness of proposed remedy in the setting of the 2014 state budgets for EGU reductions. Issues are both legal and a concern for some level of EGU system control installation equity between nearby states and between facilities with differing coal types which are dispatched within the same electricity markets. In the setting of budgets and within its allocation mechanism supporting a preferred trading program, EPA's budgets and allocations appear to reward states and utility systems that have delayed the longest in setting firm emission control installation schedules - whether the demonstrated progress results from consent decrees, state policies, other program compliance or basic corporate direction. [EPA-HQ-OAR-2009-0491-2829.2, p.7]
Modeling of the depth of the residual contribution problems shown after the implementation of the proposed remedy may also be biased low regarding summer sulfate and winter nitrate impact on PM formation (potentially up to 10% average and higher at peak). This suggests certain source areas might meet thresholds for no residual contribution during the 2nd and 3rd quarters under the 2014 remedy assessment when in fact residual contribution from the EGU sector still needs reduction in all seasons. This bias is inherent in the most current modeling platforms and needs to be accounted for - if not in the Transport Rule #1, certainly in following program steps to address 110(a)2(D). [EPA-HQ-OAR-2009-0491-2829.2, p.7]
Overall Budget Setting Framework
Summary - The program first needs to focus on achieving reasonably fixed state EGU emission budgets (including variance in EGU operation) that are identified for addressing significant contribution. The timing for meeting final budget levels by 2014 or in pursuant phases (if necessary) must follow technical feasibility. The Transport rule default allocations for 2012 and 2013 need to more accurately reflect actual operations or CAIR 2010 allocations. Allocations for 2014 and after need to be equitably distributed on a basis other than IPM predicted emission levels with provisions for periodic re-distribution such as every five years. At a minimum EPA needs to provide the States default alternative mechanisms within the rule for distributing allowances based on heat input and generation output and provide abbreviated SIP pathways. Full emissions trading and reasonable flexibilities should be allowed for the interim years (2012 and 2013) with trading increasingly limited in 2014 and after towards addressing full EGU significant contribution in a fashion that is creditable towards attainment demonstrations. [EPA-HQ-OAR-2009-2829.2, p.8]
Alternative allocation methods - EPA should provide default FIP allocations or mechanisms within the rule for distributing allowances on a heat input or output basis. If such alternatives can not be directly provided they should be allowed through abbreviated SIP mechanisms. Any method considered should provide a mechanism to periodically update the allocation of allowances. [EPA-HQ-OAR-2009-2829.2, p. 11]
EPA requested comment on alternative approaches, specifically on a heat input basis, for allocating allowances to affected sources. Wisconsin prefers EPA to use a historic baseline of either heat input or generation output versus IPM modeled emissions. The best approach, however, is to use generation output which is consistent with any potential greenhouse gas requirement. [EPA-HQ-OAR-2009-2829.2, p. 11]
Wisconsin feels aligning allocations based on actual operation instead of emissions is more appropriate for addressing electric reliability and for the equitable distribution of control effort among utilities. For units recently added to the fleet, EPA can apply the current proposed allocation method of assuming reasonable capacity factors and actual emission rates. Use of available actual year data has the benefit of collecting for deficiencies in the IPM modeling inputs and results. [EPA-HQ-OAR-2009-2829.2, p. 11]
EPA has used historic operational information under the CAIR rule and in evaluating variance needs under the Transport Rule. If EPA does not use historic activity data then, at a minimum, EPA should use the heat input or generation modeled by IPM rather than emissions to distribute allowances. In using heat input or generation the allocation of NOx allowances should be inclusive of all sources in the program. For S02 the appropriate method is to distribute allowances over only those sources that significantly contribute (e.g. - just coal EGU units or units fired by any fuel above a minimum sulfur content). [EPA-HQ-OAR-2009-2829.2, p. 11]
Whether under the proposed FIP allocation scheme or an alternative approach, EPA should provide a mechanism for periodically updating the allocation of allowances. It is not appropriate for allocations to remain fixed into the future as the generation fleet will change and dispatch evolve in response to actual generation requirements, renewable generation requirements, and future environmental regulations. EPA's current approach of placing retired unit allowances into the new source set-aside after seven years is not adequate to address these issues. An updating system was the default approach incorporated into EPA's CAIR model rule. And as adopted in the CAIR NOx SIP, Wisconsin found a five year window of rolling updates based on output generation to be appropriate for addressing these multiple issues. [EPA-HQ-OAR-2009-2829.2, p. 11]
To address alternative approaches, Wisconsin requests EPA incorporate a default mechanism into the finalized Transport Rule. This can best be done by simply incorporating the appropriate formulas for allocating allowances based on both generation output or heat input approaches. The states should be provided this elective directly within the rule. This serves to allow each state to determine the most appropriate approach for a seamless transition between the CAIR rule and Transport Rule. Within such a structure states can fully address technical corrections to base data which may affect distribution of allocations. Incorporating these approaches by default into the rule is critical as EPA's current approach does not provide states enough lead time to adopt a separate SIP. EPA could also provide the states a mechanism for adopting abbreviated SIP such as that provided under the CAIR rule.  [EPA-HQ-OAR-2009-2829.2, pp.11-12]
Another approach to providing alternative allocations is for EPA to utilize existing CAIR NOx SIP allowance information. The Transport Rule eliminates CAIR SIP mechanisms for several states which appear to meet the legal issues being addressed by the Transport Rule FIP allocations. Wisconsin is one such state with it's CAIR SIP rule for distributing CAIR NOx allocations based on recent generation output of the affected units. Other such states with an output allocation system provided in their CAIR SIP include Arkansas, New York, and New Jersey. Wisconsin asks EPA to strongly consider working from existing CAIR SIP NOx allocations which meet the necessary legal criteria, such as CAIR NOx output based allocations, as a basis for distributing Transport Rule emission budgets for both 2012 and 2014. As noted above, new unit information would need to be added and would adjust actual total allocations. This allocation of FIP allowances can be accomplished by proportionally distributing the Transport rule NOx and S02 emission budgets according to the CAIR NOx allocation of allowances. And in Wisconsin's case, where the NOx CAIR 2010 emission budget is less than the proposed Transport Rule NOx emission budget, EPA should consider directly adopting Wisconsin's CAIR NOx allocations as default TR NOx FIP allocations. Directly adopting Wisconsin's CAIR NOx allocations for the 2012 and 2013 TR NOx allocations is also consistent with EPA's intent to reflect current existing controls operated on a year round basis and accounting for operational flexibility. For reference Wisconsin's allocation of NOx CAIR allowances for 2010 through 2014 and a calculated basis for new units since the implementation of CAIR is provided in Appendix A [See EPA-HQ-OAR-2009-2829.3, p.1 for comments pertaining to Appendix A] and can also be referenced under NR 432.03, Table 1, Wis. Adm. Code. [EPA-HQ-OAR-2009-2829.2, p. 12]
Transport Rule default allocations - The Transport Rule as proposed will provide a default allocation of allowances based on IPM's predicted unit-by-unit absolute emissions levels. This approach is not preferred but technical comments and corrections are provided here and will be addressed again in comment to the current Transport Rule NODA (Sept 1,2010). [EPA-HQ-OAR-2009-0491-2829.2, p.12]
From a general approach, allocating allowances according to IPM modeled emissions biases control requirements to specific emission units. This automatic bias may not be consistent with best approaches or determinations made by state agencies which regulate electric utilities such as our Wisconsin Public Service Commission. Once again, the use of IPM may be consistent with setting state level requirements and assessing program control costs and schedules. But it is not appropriate for setting individual unit control requirements as criteria outside the IPM universe are part of a source and state decision process for applying controls. [EPA-HQ-OAR-2009-0491-2829.2, p.12]
From a practical point of view there are several concerns that must be addressed in using IPM results for setting allocations. In setting the default FIP allocations EPA directly applied the IPM predicted emissions for each unit and removed an additional 3% for the new source set-aside. By 2014 utilities may be able to respond to an allocation of allowances as provided through IPM modeling. But for the initial 2012 emission requirement this approach is likely to set more stringent and problematic requirements, at least for some individual units, than intended by EPA. These problems are amplified for facilities that have installed state-of-the-art emission controls that are already operated in an optimized fashion. If the IPM model is not accurate, sources which are not part of a larger system can be made dependent on purchasing emission credits to demonstrate compliance. At best if EPA corrects IPM inputs and 2012 emission budgets to reflect existing controls (as previously discussed) this leaves little room for operational variability (see previous comment on setting the level of the 2012 budgets). [See [EPA-HQ-OAR-2009-0491-2829.2, p.10 for comments pertaining to setting the level of the 2012 budgets; EPA-HQ-OAR-2009-0491-2829.2, pp.12-13]
A better approach to other sector significant contribution could be based on a simple unit-specific performance limit matrix rather than attempting a trading program for emission credits between fundamentally differing industries with differing financing and economic backdrops. An averaging component for single owners with multiple facilities could provide some level of flexibility as long as trading occurs within single area air sheds [but potentially could occur on an interstate basis if in close proximity]. [EPA-HQ-OAR-2009-2829.2, p. 13]
Preferred Program Approach - Background and Starting Budget Level - Technical assessment of the preferred inter-state trading/banking program remedy indicates a high sensitivity to levels of allowed banks and the net level of out-of-state purchased allowances that may be used for compliance in a given year. EPA has also indicated that any effort to carry forward banked CAIR program allowances into the Transport Rule would confound the intended emission reduction intent of the program during the critical 2012-2014 period and might ultimately lead to banks of allowance credits at a scale that would forestall controls installations needed for attainment. Therefore Wisconsin finds EPA's approach to current banked emissions reasonable. EPA needs to start the new FIP programs at budget levels achievable in 2012, but with modest flexibility built in to address both variability and normal planned compliance margins. The real target control level for the first phase should come in 2014 in order to preclude the need for standing allowance banks in 2012. [EPA-HQ-OAR-2009-0491-2829.2, p.8]
Wisconsin does fully understand EPA's need to align the 2012 and 2013 allocations with actual emissions based on existing controls for both S02 and NOx emissions if it intends to start an all new banking program. For NOx, the most appropriate means may be to utilize existing CAIR NOx allocations (as discussed below). Another approach is for EPA to use the established CAIR base activity level and incorporate new units newly operated since that time. EPA can simply address existing controls by using the base activity date along with the appropriate emission rates. [EPA-HQ-OAR-2009-0491-2829.2, pp.8-9]
Banks under the new programs should build adequately between 2012 and 2014 and if targets are appropriately deep will naturally limit the scope of excessive new bank build-up through 2015. Wisconsin has consistently supported separation of Title 1 and Title 4 trading programs and agrees with EPA's interpretation of the Court finding indicating a need here for that separation. [EPA-HQ-OAR-2009-0491-2829.2, p.9]
The finalized assessment of significant contribution developed in support of this Transport Rule needs to provide more certainty of needed additional reduction targets from both EGUs and non-EGU sectors, particularly for NOx emissions, in light of the revised ozone standard now expected later this fall. [EPA-HQ-OAR-2009-0491-2829.2, p.13]
If EPA determines that an interstate trading/banking program is the final rule structure, it should limit future allowance allocation to ensure the current allowance allocations don't confound the timing of necessary additional contribution reduction achieved via actual emission controls installations by the sector. Program structure should detail all aspects including remedy timing for additional controls phases. As noted earlier, a major remedy improvement in this rule would be the next budget adjustment years and a target scope for the additional reduction levels - even if a range rather than a specific budget amount is included for the later phases in this rule. Wisconsin recommends 2016 as a next budget year after updated 2014 targets for EGOs for both NOx and S02. [EPA-HQ-OAR-2009-0491-2829.2, p.13]
Sunbury Generation LP
Under the Proposed Rule, emission allowance allocations to existing units are determined based on the unit's fractional share of emissions, as reflected in the emissions budget for the state in which the unit is located. Accordingly, under EPAs proposed approach, noted above, 'the allocation is adjusted downward, if the unit has additional pollution controls projected to be online by 2012.' 75 Fed, Reg, 45309. [EPA-HQ-OAR-2009-0491-3615 ,p.4]
Relative to Sunbury, in determining the proposed SO2 allowance allocations for the affected EGUs at the Facility, EPA considered (and is effectively requiring) emissions reductions achievable though the installation of the Proposed Scrubber by January 2012. See 'Attachment' to TSD for the Transport Rule, ('State Budgets, Unit Allocations, and Unit Emissions Rate: Field Descriptions for Detailed Unit-Level Data', EPA, Office of Air and Radiation, July 2010, Document ID No. EPA-HQ-OAR-2009-0491-0071.4 (available at http://www.regulations.gov/search/Regs/home) (identifying a downward '[a]djustment made to 2012 projected annual SO2 emissions', based on a 'dispatchable FGD [i.e., scrubber expected to be online by 1/112012' for certain boilers at the Facility). That is, Sunbury's SO2 allowance allocation was adjusted downward on the basis that the Facility took steps to secure authorization to install the Proposed Scrubber. However, as stated above, the Facility has not yet moved forward to any significant extent with the construction of the Proposed Scrubber. Thus, the Facility cannot provide any assurances, at this time, that it will complete installation of the Proposed Scrubber in the future. [EPA-HQ-OAR-2009-0491-3615, p.4]
EPA's proposed approach of requiring emission reductions that would (theoretically) be achieved by operation of a scrubber that may not be constructed at some future time, where there is currently no applicable statutory or regulatory basis for requiring such installation, is improper, arbitrary and capricious, and unsupported by any applicable legal standard. Instead, EPA's calculation of allowance allocations under the Proposed Rule should be based on the Facilty's current actual emissions, taking into account only those control devices which are already in operation, and for which there exists a legal basis requiring such operation. At a minimum, any consideration of the operation of the furure operation of a control device that is not currently operating must relate only, if at all, to the extent that the control device is assured to be operating, and legally required to be operating, by the relevant compliance dates. [EPA-HQ-OAR-2009-0491-3615,pp.4-5]
Because there is no legal basis requiring the installation of the Proposed Scrubber at the Facility, Sunbury's allowance allocation. under the Proposed Rule should not be based on the assumed installation and operation of the Proposed Scrubber by 2012. Further, even if it is determined that it is appropriate, for purposes of determining allowance allocations, for EPA to assume operation of a planned control device for which there is no legal basis supporting its installation, it is not feasible for Sunbury to install the Proposed Scrubber before January 2012. Indeed, by EPA's own reasoning, 'it is not possible to require the installation of post-combustion SO2 controls (scrubbers) ... before 2014 ... because it takes about 27 months to install a scrubber .... ' 75 Fed. Reg. 45281. Instead, EPA acknowledges that SO2 reductions from operating existing Scrubbers - as opposed to scrubbers that are simply planned and have not yet been built - up to their design removal efficiencies is possible by 2012. Id. See also 75 Fed. Reg. 45273 (EPA acknowledges that it takes approximately 27 months to build a ... Scrubber ... to reduce SO2 emissions ... , so if the [proposed Rule] is finalized in mid-2011, emissions reductions from scrubbers by 2012 or 2013 can only reasonably be achieved if that Scrubber either exists today, or it is currently under construction'). As explained above, the Proposed Scrubber has not yet been constructed, and the Facility has not moved forward to any significant extent with the construction of the Proposed Scrubber, nor are there any other scrubbers currently in operation at the Facility. [EPA-HQ-OAR-2009-0491-3615, p.5]
EPA's proposed methodology for determining unit-specific allowance allocations under the Proposed FIP is inappropriate and inequitable as applied to Sunbury
To determine tho proposed allowance allocations for affected EGUs in Pennsylvania, EPA considered several factors, including projected emission levels. EPA attempted to project emission rates based on its own prediction of future anticipated generating rates, as reflected in different modeled projections. EPA then uses these predictions to determine allowance allocations for facilities. [EPA-HQ-OAR-2009-0491-3615, p.5]
Relative to Sunbury, EPA apparently predicts a decline in operating rates in future years. In turn, EPA proposes to allocate unit-specific allowances to Sunbury at a substantially reduced rate, in large part due to the fact that EPA projects that the Facility will operate at reduced capacity compared to current levels. [EPA-HQ-OAR-2009-0491-3615, p.5]
EPA's projected rates of generation clearly understate reasonable estimations of future operations and are inconsistent with the complete operating history for the Facility. Instead, in order to more accurately forecast future operating rates based on current data, EPA should, for purposes of determining allowance allocations under the Proposed Rule, base its projected generation rates for the Facility on representative operating conditions for the facility. With respect to Sunbury, operating levels (heat input rates) during 2007 and 2008 constitute an accurate representation of the Facilty's typical operating rates, and are consistent with Sunbury's expectations for future generation. Prior to 2007, the current owners of the Facility had not completed measures to ensure consistent operation of the facility at levels approaching operating capacity and historic operating rates. In addition, following 2008, several factors, including damage to an operating unit and reduced electricity demand arising from the struggling economy, caused a non-representative decline in generation. Based on the Facility's current operating conditions, Sunbury fully expects that future generating rates will be consistent with those demonstrated between 2007 and 2008. Use of 2007 and 2008 generating rates in predicting future operating rates for the Facility would yield meaningfully higher - and more accurate - allowance allocations for Sunbury under the Proposed Rule. [EPA-HQ-OAR-2009-0491-3615,pp.5-6]
Contrary to EPA's proposed approach for the Sunbury Facility, EPA proposes to provide increased allowance allocations to other EGUs, many of which are not materially distinguishable from the Sunbury Facility relative to issues bearing upon future generation rates. In this way, the Proposed Rule reflects judgments by EPA regarding relative electric generating distribution among various sources. By proposing allowance allocations consistent with these relative electric generating rates, EPA would effectively promulgate regulatory standards that drive the distribution of generating capacity among source types. Any such judgments regarding relative electric generating capacity among affected sources are completely inappropriate for EPA to determine, inconsistent with the stated objectives of the Proposed Rule, and contrary to statutory mandates imposed on EPA through the CAA. [EPA-HQ-OAR-2009-0491-3615, p.6]
Tenaska, Inc.
Tenaska believes the Proposed Transport Rule would achieve beneficial results faster if allowances are allocated based on heat input, rather than emissions, over the three previous years. This information is readily available and is consistent with agency past practice. Use of emissions in allocating allowances promotes continued emissions and penalizes low emission density sources. Use of heat input encourages higher efficiency and lower emissions. [EPA-HQ-OAR-2009-0491-3705,p.3]
The allowance allocations should be updated at frequent intervals (e.g., triennially) based on the previous three years' operating data. Such reallocation should apply well-articulated criteria that reward efficiency and low emissions and account for recently completed rulemakings under other programs.  [EPA-HQ-OAR-2009-0491-3705,p.3]
Retired units should not continue to receive allowance allocations beyond the triennial cycle in which retirement occurs. Retired unit allowances would then be available to new and existing units which will be obligated to increase operations to provide power in place of the retired units. [EPA-HQ-OAR-2009-0491-3705,p.3]
The Current Situation in the Energy Markets - Why Adiustments to Allocation are Necessary.
As a commodity, energy has always been subject to uncertainty caused by business cycles and attendant fluctuations in energy prices, as well as the high capital costs and long lead times of developing new energy infrastructure . To some extent, power producers have been able to manage these business risks by entering into long-term contracts with power purchasers. With the financial risks in check, the projects have been able to absorb greater risks in other areas such as accepting lower emission limits as Best Available Control Technology (BACT). The tradeoff is that the power generator has little, if any, say over when it must operate; the customer makes this decision based on market conditions. [EPA-HQ-OAR-2009-0491-3705, p.5]
EPA is proposing to base allocation of allowances on a time period in which market conditions did not favor operations of low-emitting sources as much as they do now and are projected to favor them in the future. This problem is compounded because EPA's proposed use of emissions as a measure of allocation favors higher-emitting sources by definition. Thus, there is a real risk that allocations based on time periods during which low-emitting sources were not called on to operate much will restrict those low emitters in the future. This is especially true in states where there are limited allowances available for intrastate trading and limited interstate trading . Moreover, the long-term nature of the contracts increases the risk that one party or the other will suffer a disproportionate risk of unforeseen or inequitable regulatory or other costs. Thus, while long-term contracts coupled with equitable regulation promotes more financially stable, lower-emitting generation. In contrast, inequitable and inflexible regulation can lead to adverse consequences regardless of intentions.  [EPA-HQ-OAR-2009-0491-3705,pp.5-6]
Events since 2008 have compounded the complexity and uncertainty in the energy marketplace as never before. These uncertainties can be broken down into: (1) demand uncertainty ; (2) supply uncertainty ; (3) distribution uncertainty ; (4) regulatory uncertainty ; and (5) price uncertainty. [EPA-HQ-OAR-2009-0491-3705, p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-3705, pp.6-11 for a detailed discussion on these uncertainties.]]
Proposed Initial Allocation Based on Heat Input Over Previous Three Years
EPA specifically requested comments on the proposed allowance allocation system. See 75 Fed. Reg. 45309. EPA's proposal would initially allocate allowances based on actual heat input in 2008 and emissions rate in 2009, as well as projections of emissions from economic modeling. This is flawed for three reasons. First, using actual and projected emissions as a basis for estimating state budgets is reasonable for the pollutants in question because EPA's objective of reducing emissions at the state level. Nevertheless, allocation to units on the basis of emissions, actual or projected, rewards units with high emissions without regard to heat input, output or efficiency . As EPA recognizes, under this scheme, units which invested in control equipment received fewer allowances than those units which failed to do so. See 75 Fed. Reg. 45311 . Such lower-emitting sources are placed at a disadvantage . This allocation scheme is contrary to the purpose of the Transport Rule, which is to reduce the emission and transport of ozone and PM2.5 precursors by encouraging investment in control equipment. The best way to achieve that goal is to allocate based on output . Doing so would reward lower emission intensity (i.e., emissions per unit output and efficiency of the units) . One might argue, however, that this would be inequitable to larger, older, less-controlled facilities. Therefore, a compromise would be to allocate based on the heat input of the unit. EPA suggests this approach and requested comments on it. Id. This would reward efficiency while not penalizing older generating units. There is precedent in the Clean Air Interstate Rule and the NOx SIP Call where heat input was used as a basis for unit allocations. Because use of heat input would affect allocation among units within a state and not allocation among states, it does not implicate the issues caused by interstate trading in the CAIR rule. [EPA-HQ-OAR-2009-0491-3705, pp.11-12]
The second problem is in using the selected timeframe (2008 heat input and 2009 actual emissions) for allocating allowances . No one year is 'representative' but 2008 and 2009 are anomalies. As explained above, due to the financial meltdown and unusually mild weather, that was an unrepresentative period in the electric generating industry. As the U.S. Energy Information Agency stated,
In 2009, U.S. energy markets continued to show the impacts of the economic downturn that began in late 2007 . After falling by 1 percent in 2008, total electricity generation dropped by another 3 percent in 2009. Although other factors, including weather, contributed to the decrease, it was the first time in the 60-year data series maintained by the EIA that electricity use fell in two consecutive years. [EPA-HQ-OAR-2009-0491-3705,pp.12-13]
U.S. EIA 'Energy Outlook 2010,' www.eia.doe.gov/oiaf/aeo/pdf/0383(2010).pdf. The preamble to the Proposed Transport Rule states that the budget and emission reductions required should be set for the 'average year' (See 75 Fed. Reg. at 45290); such is not the case with 2008-2009 in term of energy consumption, production or emissions . Using 2008-2009 as a baseline year for purposes of allocation will serve only to inhibit economic development. [EPA-HQ-OAR-2009-0491-3705, p.13]
To address the recent volatility in the energy markets, Tenaska suggests that the allocation of allowances under a state budget be based on a unit's maximum heat input over a three-year period as a fraction of the sum of all electric generating units' maximum heat input over the same period. This will have the effect of leveling out the playing field and providing 'liquidity' to the allowance market. The result will be an acceleration of economic activity, consistent with the Administration's goals. [EPA-HQ-OAR-2009-0491-3705,p.13]
Third, while Tenaska does not contest the use of projected emissions from Integrated Planning Model (IPM) runs for the establishment of state emission budgets, such modeling should not be used for unit-level allocations. While IPM might be adequate for state level modeling, the unit-level results from the IPM dispatch model are driven by subjective input assumptions and distorted by modeling limitations . The future price of natural gas is an example of a subjective input assumption. There is considerable uncertainty surrounding that price due to the recent shale gas developments and fluctuating demand. In the IPM model, EPA uses an input assumption for the projected price of natural gas and any such number is certain to be wrong. This input alone can significantly alter the dispatch result for gas-fired generation. Other inputs which impact projected unit-level generation include economic growth, demand intensity, renewable generation additions, timing and location of plant retirements, timing and location of plant additions, and market structure. [EPA-HQ-OAR-2009-0491-3705,pp.13-14]
As an example of its inherent limitations, IPM models the United States electric markets as a number of large market zones with limited electric transfers between those zones . While this simplification is common and necessary for modeling purposes, this is not how the majority of markets covered by the Proposed Transport Rule are actually dispatched. MISO, PJM, NYISO and ISONE are nodal markets where each plant dispatches based on its relative daily bid price and the power price at its point of interconnection . Thus, the IPM model will understate the generation from units in constrained areas while overstating the generation in unconstrained areas. [EPA-HQ-OAR-2009-0491-3705,p.14]
It is not clear whether IPM is able to accurately model unit dispatch constraints such as start costs, start fuel costs, minimum run time after a start, minimum down time after a shutdown, minimum operating levels of a generating unit with a corresponding heat rate, etc . These unit-level modeling inputs will significantly impact projected unit level generation. [EPA-HQ-OAR-2009-0491-3705, p.14]
Finally, we are unable to reproduce the allocations in the technical support document and we attribute this deficiency to the IPM model and its inputs. Use of past heat input information poses no such problem. EPA could promptly make allocations based on heat input and submit them for review in a notice of data availability. [EPA-HQ-OAR-2009-0491-3705, p.14]
Allowance Allocation Should be Updated at Planned Intervals.
EPA has recognized that it will be necessary to update the state budgets and the allocations of allowances in light of new rules. 75 Fed. Reg. at 45301 . Otherwise, entirely new rulemakings would be required to update the standards or there would be a potential conflict between the Transport Rule and the new rules, as well as with SIP amendments to implement them. Periodic updating is also necessary because of the dynamic changes in the electric generation sector. Simply put, and borrowing from the Securities and Exchange Commission disclaimer language: '[p]ast performance does not guarantee future results.' Data shown in Figures 2 and 3 show that combined-cycle natural gas generation has quadrupled over the last ten years, while other forms of generation have been either declining or stable . It is highly likely that natural gas-fueled power generation will continue to increase significantly in the future . The periodic updates, i.e., at least triennially, would allow for adjustments to accommodate increased use of clean fuels. This three-year period is consistent with EPA's plan to record new allocations due to the new unit set aside and retirement. See 75 Fed. Reg. 45311. [EPA-HQ-OAR-2009-0491-3705,pp.14-15]
Tenaska also believes it is important for orderly investment in new energy infrastructure to have clear rules for the triennial review. If those principles are changed, then investment will be discouraged. Therefore, it is best to put in place a set of rules indicating how the allocations will be changed in the future so that behavior can be modified accordingly . We have seen from the vacatur of the CAIR rule, that allowance markets fall into chaos when the rules are changed and values are seriously discounted. Thus, it is important that the Transport Rule be made with provisions that allow updates to take into account changes in input in the various states and units within those states. [EPA-HQ-OAR-2009-0491-3705,p.15]
In addition to changes in the actual emissions and operations of EGUs going forward, we can contemplate that state budgets will also need to be changed to accommodate the anticipated effects of new NAAQS and other proposed rules. A rule that can be updated to accommodate these anticipated changes will be inherently more stable, offer greater liquidity, and support investment in lower emitting sources than an inflexible rule with fixed budgets. Such a rule would have to be scrapped if state budgets must be tightened in the future. The Courts have not allowed redefinition of the value of Acid Rain Program allowances. This suggests that permanent allowance allocations place an unnecessary regulatory burden on the proposed rule to anticipate needs for future adjustments in state budgets and the related unit allocations. [EPA-HQ-OAR-2009-0491-3705,pp.15-16]
Retired Unit Allowances Should Be Auctioned.
We also suggest that any retired units' allowances be auctioned in each state as part of the triennial readjustment . This would gradually remove from the market the distorting effect of free allowance allocations based on historical operations or, even worse, historical emissions. Allowance auctions align the markets with environmental performance and encourage the use of cleaner, more efficient technologies . Auctions also assure availability of allowances in a system with constrained interstate trading. [EPA-HQ-OAR-2009-0491-3705, p.16]
Texas Chemical Council
V. EPA Did Not Provide Enough Allocations for Many Texas Cogeneration Facilities
Many Texas cogeneration facilities were not provided enough allocations under the EPA proposal to continue operating during the summer ozone season. It is also unclear how EPA developed a basis for determining allowances, a fact which is extremely disconcerting. [EPA-HQ-OAR-2009-0491-2815.1, p.5]
Vectren Corporation
Proposed Transport Rule unfairly disadvantages clean units such as Vectren's. [EPA-HQ-OAR-2009-0491-2654.1, p. 3]
What is perhaps a glaring example of the law of unintended consequences, EPA's proposed cap-and-trade rule will in some states such as Indiana unfairly disadvantage power companies that have already invested in pollution controls by awarding more emission credits to those utilities that have not installed controls. This is due to the unprecedented change in the approach that EPA has used for allocating emission allowances. [EPA-HQ-OAR-2009-0491-2654.1, p. 3]
Under the current Transport Rule proposal, EPA would distribute allowances based upon a facility's historic emissions. By contrast, under the Acid Rain Program, the NOx SIP Call, and the Clean Air Interstate Rule, allowances for NOx and S02 were allocated based upon a unit's heat input, or the amount of fuel used by the generating unit. This essentially created a level playing field for all similarly situated coal-fired units. Those units that were already controlled received allowances based upon a 'neutral' factor (i.e. heat input). Thus, they were not penalized for having already made the necessary emission reductions. Those companies who chose to construct pollution controls were able to sell excess allowances to offset the cost of installing the controls. Indeed, in highly regulated service territories such as Vectren's, 80-90% of the proceeds of the sale of emission allowances are credited back to the customer. [EPA-HQ-OAR-2009-0491-2654.1, p. 3]
A review of the emission allocation tables provided in the proposed rule clearly illustrates the inequities created by this new approach to the emission allowance allocation methodology. Vectren's units are already controlled and emissions are already low, yet an emission allowance allocation methodology based solely upon historic emissions, and not heat input, places the emission reduction baseline off an already low emission rate. Thus the starting point for further emission reductions for a unit with controls is significantly lower than for an uncontrolled unit. A review of the emission allowance allocation tables attached to the proposed rule clearly indicates that EPA allocated sufficient emission allowances to uncontrolled units in 2012 to allow those units to continue to operate uncontrolled until 20 I4. Thus, EPA is providing sufficient allowances to uncontrolled units to allow them to maintain 'status quo' until 2014, while controlled units such as Vectren's are required to make significant reductions in 2012 - a full two years before the uncontrolled units - and then further significant reductions in 2014. [n addition, a company that takes one of these uncontrolled units off-line for significant periods of time to construct a scrubber and / or SCR will be able to bank the resulting excess allowances for future use. Since clean units are not provided these excess allowances, companies with clean units such as Vectren that have already made the investment in pollution controls will not have the same opportunity to bank excess allowances, which sets up a competitive disadvantage and unintended penalty for having constructed actual controls on its units to comply with previous EPA emission reduction programs. [EPA-HQ-OAR-2009-0491-2654.1, pp. 3-4]
EPA unfairly used a recessionary emissions baseline year. By using an unrepresentative and depressed recessionary year for an emissions baseline, EPA has in effect imposed a 'double whammy' on clean units such as Vectren's. As indicated above, controlled units are already placed at a competitive disadvantage under the proposed Transport Rule by EPA's use of an altered emission allowance allocation methodology based solely upon historic emissions (which were already low for these units) instead of a neutral heat input factor. Compounding that clean penalty is the fact that the historic emission period that EPA bases its emission reduction requirements on was historic for its recessionary and steep decrease in generation (and thus emissions), and simply not representative of future electric demand and necessary generation to meet that demand. As a consequence, EPA is requiring steep reductions II·om an unrepresentative and artifically low emission reduction baseline. [EPA-HQ-OAR-2009-0491-2654.1, p. 4]
If despite the fact that its proposed emissions allocation methodology imposes a clean penalty on controlled units such as Vectren's EPA should stick with this flawed methodology in its final rule, at a minimum EPA should re-allocate emission allowances based upon a representative three year average emissions baseline for the affected units. While there may be differing opinions on how long it will take for the economy to rebound from its recessionary lows in 2009, no one bclieves the economy - and thus industrial demand for electric generation - will stay permanently depressed. Within the last 6 months Vectren has been fOliunate to see increased demand from a new industrial customer. Any economic recovery resulting in increased demand for generation was simply not taken into account when EPA established its recessionary emissions baseline, and makes the already low individual plant emission caps even more challenging to meet as the economy improves. [EPA-HQ-OAR-2009-0491-2654.1, pp. 4-5]
Virginia Department of Environmental Quality (VDEQ)
Activity data from the Clean Air Markets Division (CAMD) website or other sources rather than IPM projections should be used to allot allocations of SO2 and NOx to units in future years. Activity data was the basis for the NBTP allocations as well as the CAIR allocations. Only a small number of units do not report 12 months of activity data to CAMD. For those units that do not report 12 months of activity data to CAMD, additional activity data may be garnered from a variety of sources such as the National Emissions Inventory (NEI), State inventory databases, and the Energy Information Administration. EP A should not use IPM to estimate future activity data. Use of IPM adds an enormous amount of uncertainty to an already uncertain process. IPM is proprietary software that does not allow stakeholders to review decisions used to create predictions nor does it allow independent verification of the results without an unacceptable associated cost. Past use of IPM results for forecasting activity necessitated significant data revisions due to forecasts of unrealistic or inappropriate operations of significant emissions units in or near sensitive regions such as nonattainment and maintenance areas. Previous years' activity data, on the other hand, is readily available from a variety of sources in the public domain. [EPA-HQ-OAR-2009-0491-2595.1, pp.2-3]
Virginia Independent Power Producers
EGUs Must Have Access to Sufficient Allowances To Meet Customer Demand for Electricity.
AU EGUs - utilities, independents, cooperatives and others - operate in the public interest in that they provide a vital commodity - electricity - for public consumption on demand. The entire economy and well being of the Nation depend on the availability of sufficient quantities of affordable electricity available on an 'as demanded' basis. A regulatory system that artificially restricts the availability of required emissions allocations will threaten the integrity of the electricity supply system and, by extension, the well being of the Nation. [EPA-HQ-OAR-2009-0491-2640.1, p.3]
Unlike other industries, electricity producers (a) cannot feasibly store their product in inventory and (b) cannot tolerate supply disruptions. If EGUs are not provided sufficient emissions allocations to operate in the public interest to supply electricity as demanded by customers, supply disruptions will occur. In the electricity industry. supply disruptions are not matters of inconvenience; they are matters affecting the health, welfare and employment opportunities of the citizenry at large. [EPA-HQ-OAR-2009-0491-2640.1, p.3]
Furthermore, VIPP's member companies sell electric capacity and energy under longterm Contracts to Dominion (Virginia Power). The facilities of the member companies are operated pursuant to contracts with Dominion that do not allow for the pass-through of costs associated with emissions allowances. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers, or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators such as VIPP's member companies can be severely impacted by the requirement to purchase emissions allowances. Further. long-term contractor generators do not exereise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. [EPA-HQ-OAR-2009-0491-2640.1,p .3]
For these reasons, it is imperative that independent power producers with long term contracts (like VIPP's member companies) be given sufficient emissions allocations to generate electricity as demanded by customers, and be provided access through intrastate and interstate trading mechanisms to acquire allowances as needed. Failure of the Transport Rule to provide sufficient allocations and access to efficient trading mechanisms has the potential to plunge the Nation into a worse and deeper recessionary period than already exists, causing great harm to the Nation's citizens, its businesses and industries. [EPA-HQ-OAR-2009-0491-2640.1, pp.3-4]
Congress previously recognized that long-term comract generators do not have a mechanism to pass through new environmental costs to their power purchasers, and exempted these plants from the Acid Rain Program under the  1990 Clean Air Act Amendments so long as the long-terml agreements remained in effect. As Congress has previously done, EPA should recognize the unique situation of long-term contract generators that cannot pass along the costs of emissions allowances to their customers. EPA could do this by allocating to long term contract generators any surplus allowances that remain in the new unit set-aside for any control period in which the long term comment generator 's emissions exceeded its allocation due solely to a return of the facility' s capacity back to pre-recessionary levels. In other words, surplus allowances from the new source set aside would be allocated as needed to a long term contract generator in situations where their emissions increased because the facility's heat input had increased to a level that the generator had, in fact, achieved in any calendar year or ozone season since 2005. This would provide relief for long-term contact generators who experience an increase in utilization from the levels EPA has relied upon in establishing allocations, without providing a permanent allocation that could be sold to others. [EPA-HQ-OAR-2009-0491-2640.1, pp.3-4]
we energies
We support EPA's proposal to continue allocating allowances to retired units during the 3 consecutive years of non-operations plus an additional 3-year period. The time period for this allocation should start, at the earliest, with the first year of the program. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
We agree with providing allocations to retired units for a limited period of time. Allocating allowances for a limited period time provides a retirement incentive, yet allows for a reasonable transition of allowance availability for new and continuing unit operations. Retaining retired unit allowances for a predetermined length of time also provides a system compliance margin while controls are being added to units that will continue operations. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
EPA's proposed rule should go no further than providing for accurate state allocations, thus allowing the states to apply their knowledge of facility-specific data and current and future operating schemes. This approach was satisfactory under the CAIR rule, and a similar approach would provide continuity between the current and proposed rule. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
We oppose the allocation of the state budgets to individual units as included in the proposed rule. While the mechanics of how these allocations were arrived at are not at all transparent, it appears that these allocations are based on several layers of errors, including errors in the NEEDs database, in the baseline assumptions, and in the IPM outputs. For example, We Energies receives no allocations for our South Oak Creek Units 5&6 and Valley Units 1-4 since the IPM model assumed that they would be retired, and they will not (see section on EPA Assumptions for EGU Retirement, above). [EPA-HQ-OAR-2009-0491-2629.1,p.4]
In addition, the current allocation method rewards units that have not added post-combustion controls, while penalizing those that have already added controls during the time period since CAIR was originally proposed, e.g., We Energies Pleasant Prairie units, where post-combustion controls have been fully operational since 2007 . Therefore, we advocate for state flexibility in determining final allocation budgets, and would specifically support the state budget in the transport rule to be allocated according to the proportions as reflected in the final CAIR budgets. The allocation methodology reflected in the final CAIR budgets are the result of an administrative rules process that considered several iterations of source-specific comments and information submittals. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
Banking of emission allowances is another critical rule component for We Energies. It allows us to balance allowance shortages while additional controls are being installed, and to account for annual fluctuations in generation due to unit outages and unit capacity factors. Banking provisions are critical to maintaining a reasonable compliance margin for unit operations. [EPA-HQ-OAR-2009-0491-2629.1, p.7]
West Virginia Department of Environmental Protection
[[2790.1 p.4-6]]
Proposed Budget Methodology - WVDAQ is unable to fully duplicate the 2012 or 2014 allocations for West Virginia. Some allocations cannot be replicated using the methodology outlined in the proposed Transport Rule preamble. Such a problematic situation does not allow a clear and concise understanding of EPA's allowance allocation methodology.
In the supporting RIA document, EPA explains that the base case includes the Title IV Acid Rain Program, the NOx SIP Call, and states' rules through February 3,2009. CAIR subsumed the NOx Budget Trading Program, and West Virginia repealed its NOx Budget Trading Program rules and submitted the repealed rules to EPA as a revision to the SIP. Therefore, only the NOx SIP Call provisions for internal combustion engines and cement kilns are still on the books in West Virginia. EPA appears to count on the NOx SIP Call in the base case even though the program is effectively dismantled and not in force. WVDAQ believes that because CAIR was ultimately remanded and not vacated, EPA should rely on CAIR for a real-world base case analysis.
Use of IPM Model - WVDAQ questions the use of IPM predictions as the basis of determining emission budgets and allocations. In the past, IPM has delivered mixed results and does not appear to be a good predictor of the future, especially when applied at the source level. EPA has previously indicated that IPM is f!:. solution, not the solution, implying that there are different methods to determine transport emission budgets and allocations. Based on the constraints applied, IPM provides a least-cost solution, but IPM may not be the only method to determine emission budgets and allocations. Our experience with past applications of IPM shows that it can and does make problematic and significant mistakes, such as incorrect predictions of shut down or non-operating units, or applying controls for sources which the owner has no intention of installing.
As an example of the problematic use of IPM, the TSD Allocation Table indicates that IPM projections are used as the basis of the S02 allocations, yet reported emissions data are used as the basis of the NOx annual and ozone season allocations. A review of the docket spreadsheet BADetailedData.xls, on the Allocations and Rate Limits worksheet, under the column headings Heat Input Assumed in Annual NOx Allocation and Heat Input assumed in 2012 S02 Allocation, there are differences of more than 100 percent in the heat inputs which are used as the basis of the NOx and S02 allocations for 2012. For instance, Albright Unit 1 (ORIS Code 3942), has a Heat Input Assumed in Annual NOx Allocation of 2,050,480 mmBtu and a Heat Input assumed in 2012 S02 Allocation of 5,960,450 mmBtu.
In this example, the heat input assumed for Albright's S02 allocations is 290 percent of the heat input assumed for the NOx allocations for the same period. WVDAQ questions EPA's decision to use a different basis (projected vs. reported data), which assumes different heat inputs for the same time periods and for different pollutants. WVDAQ believes that this is but one demonstration of how the use of IPM model results can skew emission budgets and allocations from a reasonable result.
WVDAQ also questions whether it is appropriate to allocate allowances based on IPM predicted emissions for 2012. As previously noted, it is apparent that EPA's decision to base allocations on projected (or even historical) emissions penalizes sources that have installed controls. This observation is of greater concern considering that EPA proposes to allocate to existing units one time, before the Transport Rule cap and trade programs commence. Except for non-operating units, the allocations would be permanent as base amounts, and would not be updated. As such, WVDAQ does not believe it is appropriate for EPA to use IPM projections as the basis ofthe allocations. WVDAQ therefore supports a more appropriate metric, the alternative allocation method proposed in the Transport Rule.
Alternative Allocation Method - EPA requested comment on an alternative methodology that links unit allowances directly to the way state budgets were developed. This alternative method for allocating allowances would have the effect of distributing the responsibility for eliminating all or part of a state's overall significant contribution and interference with maintenance to individual units based on each unit's share of proj ected heat input. WVDAQ believes that the alternative allocation method is more straightforward, transparent and equitable to sources that have installed controls than the proposed allocation method. EPA should maintain a consistent policy that encourages early emission reductions and rewards sources which achieve them. Therefore, we support inclusion of this alternative methodology in the final Transport Rule.
Non-Operating Units - EPA requested comment on the proposed approach for allocating allowances to non-operating units, as well as simplifying allocations by not allocating at all to non-operating units. EPA also requested comment on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the Title IV Acid Rain Program. WVDAQ believes that non-operating units should receive a time-limited allocation, and a seven year limitation would still provide an incentive to shut down certain units that may not be cost-effective to control. Not allocating at all to non-operating units will diminish or eliminate such an incentive, while allocating in perpetuity may hinder the ability to establish new units. Therefore, WVDAQ supports the proposed approach for allocating allowances to non-operating units, with the allocations transferred to the new unit set-aside after seven years.
Wolverine Power Supply Cooperative
The proposed allocation methodology departs radically from previous air act allowance allocation without explanation. 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-2009-0491-2825.1 p.4]
The proposal does solicit comment for alternative approaches, and in particular an approach based on heat in-put, p. 45311. We suggest the allocation methodology similar to that promulgated in CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This heat in-put driven system was not overturned by the court's decision in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008) ("North Carolina"). As this alternative is detailed somewhat in the proposal, allowances should be distributed based on state allowance budgets pro rata based on unit historic heat rates. 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 and could accommodate new units after 5 years of operation into this baseline. This heat input approach would eliminate perpetual allocations to most polluting units, reward consumers who purchase power from new clean sources, and overall demonstrate a rational policy. This method would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-2825.1 p.4]
We also believe that EPA's proposed allowance allocation methodology discriminates against peaking units because the baseline years of 2007  -  09 were very-low utilization years due to a combination of unusually cool summers and very depressed economy in the upper Midwest. We propose using highest heat input of a current baseline (similar to NOx SIP Call and CAIR methodology) that for first allocation includes 2010 in the baseline, and that the allocations be rolled forward annually with newly calculated baselines. We again emphasize that EPA should follow this heat-input based allocation methodology in developing state budgets, but the states should perform the actual allocations through either the FIP or SIP process. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
Wolverine's Sumpter peaking plant is a clear example of the above concerns. This plant, under its former owner, had very low duty schedules during EPA's proposed baseline due to the cool summers and very bad economy that reduced electric demand in the Upper Midwest. EPA proposal to allocate one NOx annual and ozone allowance to two of these units and zero to the other two, provides the plant with a total of two allowances for the four 85MW simple-cycle gas turbine units. Due to a warm summer in 2010, and slightly improved manufacturing load demand, this plant has required to date 8 annual and ozone season allowances, 400% greater than the proposed allocation. As the economy recovers, and as available base-load generation is in short supply due to this proposed rule, we anticipate that the Sumpter Plant will require higher utilization to meet demand and support electric reliability. We are very concerned that this plant is being penalized because it is a very clean and used in peaking duty. If a robust allowance trading program does not exist (see below), this plant will not be able to operate in future years when it will be needed most by the electric customers of Michigan. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
We support a generous new source pool of allowances that will be allocated in the proposed method in EPA's proposed remedy, and support redistribution of unused allowances to existing sources. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
Xcel Energy Inc.
I. ALLOWANCE TRADING PROVISIONS AND ALLOCATIONS.
1. The Transport Rule should protect companies that have already undertaken investment risk to reduce emissions and improve ambient air quality affected by downwind transport of pollution.
In EPA's preferred design, the Transport Rule would create a multi-tiered trading program for SO2 and NOx. Like all trading programs, trading under the Transport Rule can take place only after emission allowances are distributed to the utilities and covered sources that participate in the program. CATR would distribute the allowances based on projected emissions from each covered source in each state after removal of the emissions accounting for the state's significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-2728.1, p.2]
EPA in part based this program design on the mandates of the court's opinion regarding the Clean Air Interstate Rule ('CAIR') rule. Unfortunately, CATR does not adequately recognize and reward those companies and units that have already reduced emissions. As indicated above, our operating companies have made major investments in order to reduce emissions, including natural gas repowering at some of our largest generating facilities in Minnesota).1 [EPA-HQ-OAR-2009-0491-2728.1, pp.2-3]
[See page 3 of this comment for two examples from Xcel Energy's fleet.]
These emission reductions have played an important role in reducing ambient air quality issues in the transport region. Our customers are already paying for these emissions reductions through rate increases approved by utilities commissions in our states. The next group of emission reduction projects is likely to be more costly than the round that we have already undertaken. Unless EPA adopts an allocation mechanism to reward our early emissions reductions, the Transport Rule w/ill prove the old adage that 'no good deed goes unpunished.' Rather than recognizing this leadership and rewarding such investments, the CATR effectively punishes the company for reducing its emissions by basing the allowance allocation on projected emissions. By contrast, those companies who resisted investments in pollution control EPA reacted to the D.C. Circuit's opinion will receive much larger allocations, which they can use to finance belated investments in pollution control that Xcel Energy made several years ago. [EPA-HQ-OAR-2009-0491-2728.1, pp.3-4]
To avoid this kind of injustice, EPA can adopt a simple solution: It should allocate allowances based on historic emissions. We recommend that the Transport Rule allocate based on average emissions during any three year period between 2005 and 2009. This three year period predates most of the emission reductions undertaken as a result of CAIR and other programs and will reward companies like Xcel Energy that undertook significant emission reductions in the very recent past. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
This allocation scheme is consistent with the court's opinion in the CAIR litigation. The opinion in the North Carolina case did not address the issue of early reduction allowance allocation. Because the allocation scheme we propose here does not interfere with the protections that EPA proposes to address the D.C. Circuit's concerns, the early reduction allocation formula is not inconsistent with Court's opinion. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
Although Xcel Energy prefers an allocation methodology based on an historic emissions baseline, in the alternative we could also support the creation of a significant 'early reduction' allowance pool to reward those companies that made large investments in early, emission reductions and address the punitive effect of the proposed, forward-looking allocation model. We suggest a 10% reserve for reductions achieved since 2007 through retirement, repowering and installation of controls. We believe that such an early reduction credit set aside would adequately address overall policy objectives, including environmental effectiveness, cost effectiveness, and fairness to companies that have undertaken significant risk ha order to make progress towards environmental goals. If EPA chooses not to provide an early reduction credit set aside, it signals a large disincentive for companies implementing early reductions. This precedent would have a negative effect on future environmental compliance decision-making, dampening investments (and environmental benefits) in advance of regulation in favor of a just-in-time compliance philosophy. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
2. Xcel Energy disagrees with EPA's proposal to eventually stop allocating allowances to units that cease operations.
On pages 45310-45311 EPA requested comment on allowance allocations to nonoperating units. Xcel Energy disagrees with EPA's proposal which would stop allocating allowances to units that cease operations after three years, with those allowances being redirected into the next unit set aside. As indicated above, Xcel Energy strongly believes that coal plant unit retirement, whether in the past decade or in the future, is an important tool that utilities may utilize to meet the obligations of the Transport Rule and other environmental mandates. Xcel Energy supports having allowance allocations that do not expire. This system has worked well under the Acid Rain program and should be continued into CATR. These programs have shown that long-term allowance allocations help pay for early reduction projects. As an alternative, to induce companies to retire units, EPA should allow companies to receive the allowances for at least 10 years after retirement. Without such a term, EPA will effectively induce companies to keep older, less efficient units in service longer than needed and, likely, defer the construction of newer, lower-emitting generation. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
While we support EPA's preferred alternative, Xcel Energy is concerned about the complex trading rules and limitations in the preferred alternative. Our operations span eight states, with CATR affecting operations in three of those eight states, each with different potential obligations under CATR. The trading limitations and potential future changes under the CATR would make it very difficult for a multi-state electric company such as Xcel Energy to optimize its operations and investments. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
To create the most flexible and cost effective compliance program, Xcel Energy requests that the EPA minimize restrictions on trading and future changes to market restruction as much as possible. In particular, Xcel Energy questions the need for multiple 'trading zones' through the grouping of states. EPA's proposed variability limitation will effectively protect against the concerns expressed by the D.C. Circuit such that the trading zone limitations are not necessary. Further, these zones will severely limit the effectiveness and transparency of the allowance trading market. It effectively would create a structure that will limit trading and create incentives for creating a range of derivatives and swaps that will open the agency and the system to criticism. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
4. Xcel Energy supports the creation of a new unit allowance set aside.
On page 45310 EPA requested comment on the new unit allowance set aside provisions. New units must have allowance allocations or they will be completely dependent on the trading market. We believe that some allocations are needed for new units. Xcel Energy is supportive of the 3% allowance set aside for new units as proposed by EPA to address the risk of market limitations affecting supply for new sources. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
5. Xcel Energy supports the use of the Acid Rain Program ('ARP') allowance and recording system.
On page 45311 EPA requested comment on the form of the allowance recording and surrendering system. Xcel Energy supports using an allowance recording and surrendering system similar to that used in the ARP and CAIR. This system has proved to be accurate and reliable. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
6. Xcel Energy asks EPA to correct errors in the treatment of its Bay Front Units in Wisconsin.
Through its Wisconsin affiliate, Xcel Energy runs the Bay Front facility, a three-unit combined biomass and coal plant in Ashland, Wisconsin. Xcel Energy notes that Bay Front Units 1 and 2 are not included in CATR due to unit size, since both are less than the 25 megawatt electrical ('MWe') inclusion threshold. While both of these units primarily serve generators that are less than 25 MWe in size, they share a common steam header with Unit 5 which is greater than 25 MWe. As a result of this common header, Units 1 and 2 meet the applicability criteria of serving a generator with a nameplate capacity of more than 25 MWe. This issue has been previously addressed under the ARP and these units are included under that program. Therefore, these units should be granted allocations and included in CATR. [EPA-HQ-OAR-2009-0491-2728.1, pp.5-6]
3. Xcel Energy cautions EPA against assuming a given air pollution control device can operate effectively outside its design range.
Selective catalytic reduction systems ('SCRs') and SO2 scrubbers are designed to operate at a specific inlet and outlet concentration of the pollutant they are controlling. Generally, the outlet design value is set to the permit limit, with a small safety factor added in. Forcing a unit to operate outside of these design values increases the amount of wear and tear on the unit, which leads to more frequent malfunctions, accelerates component and catalyst replacement schedules, and shortens the life of the unit. [EPA-HQ-OAR-2009-0491-2728.1, p.9]
Adding additional control modules to increase the control efficiency is problematic, at best. This is especially true in the case where an existing electric generating unit has been retrofitted with pollution control equipment. These units are generally operating with a constrained equipment footprint, and additional control modules would be difficult and expensive, if even possible, to install. [EPA-HQ-OAR-2009-0491-2728.1, p.9]
An example of this is the Allen S. King (King) Plant, with one generating unit, which went through rehabilitation project and returned to service in July 2007. As part of this rehabilitation process, a SCR was added for NOx control, a semi-dry spray dryer absorber (SDA) was added for SO2 control, and a fabric filter baghouse was added for particulate matter control. [EPA-HQ-OAR-2009-0491-2728.1, p.9]
The CATR NOx allocation for the King Plant is based on the SCR operating at 0.081 pound NOx per million British thermal units ("lb NOx/mmBTU") due to EPA's assumption that a SCR is capable of 90 percent NOx reduction. The average NOx emission rates for King reported to EPA in 2008 and 2009 were 0.112 lb NOx/mmBTU2 and 0.087 lb NOx/mmBTU, respectively. As discussed above, King Plant is being penalized in two ways for installing a SCR earlier than requited by the Transport Rule. First, because the SCR is already installed, EPA allocates allowances based on projected emissions rather than pre-SCR emissions. Second, because the King SCR was installed in advance of the CATR, it was not designed to achieve 90% reduction, yet EPA incorrectly assumes that result in the allocation methodology. King would have received more allowances if the pollution control projects had been delayed until after the modeling for the Transport Rule had been completed. [EPA-HQ-OAR-2009-0491-2728.1, pp.9-10]
The situation for SO2 is similar. The CATR allocation is based on the SDA operating at 0.082 lb SO2/mmBTU. However, the King Plant's average SO2 emission rates reported to EPA in 2008 and 2009 were 0.109 lb SO2/mmBTU and 0.093 lb SO2/mmBTU, respectively. Thus, the King Plant is being penalized for installing a SDA earlier than required by the Transport Rule and the Rule assumes performance well beyond that required or achieved by the plant. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
By adopting the allocation methodology as proposed, EPA risks discouraging future early reduction projects, undermining its own environmental goals as discussed in Section 1.1 of these comments. [EPA-HQ-OAR-2009-0491-2728.1, p.10]

1 We are currently in the planning stages of more major investments in Colorado under the provisions of the Colorado Clean Air Clean Jobs Act, which became law earlier this year. [EPA-HQ-OAR-2009-0491-2728.1, p.3]
2 Note that the SCR was put in service in January 2008. Compliance with the 30-day rolling average limit of  0.10 lb/mmBTU was not required until July 15, 2008 (450 days after first fire on coal, which occurred April 22, 2007). [EPA-HQ-OAR-2009-0491-2728.1, p.9]
Response:
Thank you for your comment.Organization: State of Missouri Department of Natural Resources
Comment:
State of Missouri Department of Natural Resources
Page 45310 of the proposed rule describes allocations to new units that are three percent (3%) of the state emission budgets for each trading program. 'EPA proposes that after a unit is not operating for three consecutive years, the allowances that would otherwise have been allocated to that unit, starting in the seventh year after the first year of non-operation, would be allocated to the new unit set-aside for the state in which the retired unit is located.' Missouri recommends that if a unit were to retire, these allowances be distributed in a state among existing operating participants. An alternative to this would be to create a new pool from the retired unit(s) allowances, to be reserved specifically for energy efficiency within a state instead of the allowances reverting to the new unit set aside pool. [EPA-HQ-OAR-2009-0491-3806, p.5]
Response:
Thank you for your comment.Organization: Tampa Electric Company
Comment:
Tampa Electric Company
As outlined above, EPA's time constraints and inadequate supporting documentation prevented Tampa Electric from determining the accuracy of EPA's allocation based on the IPM model output. Apparent errors possibly related to model inputs or algorithms resulted in arbitrary and capricious allocation results. The proposed allocation method penalizes companies like Tampa Electric that made early commitments to reduce emissions.  Tampa Electric has been a leader in making emission reductions (making a 88% and 90% system-wide reduction in SO2 & NOx, respectively over 1998 levels), yet the proposal does not provide sufficient SO2 allowances to even operate near our current permit limits. Furthermore, the allocations are not adequate to allow operation of some units with any available control schemes. Examples of apparent errors and inconsistencies include: [EPA-HQ-OAR-2009-0491-2745.1 p.4]
[These comments were also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.54.]
At Tampa Electric's Big Bend Station, EPA allocated 3,936 SO2 allowances to Unit 2, but only 1,992 allowances to Unit 1. These units are both controlled by a common scrubber and have historically equivalent capacity factors. The illogical disparity could be due to outage schedules. Ironically, during the limited time frame that EPA used to determine the capacity factor, Tampa Electric was installing 2 SCR's as part of its $1.2 billion emission reduction initiative. It appears that Tampa Electric is being penalized for taking an outage to install controls necessary to comply with this rule. Regardless of whether or not the outage penalized the allocation, this highlights the flaws in EPA's use of a very limited baseline timeframe to develop a very important allowance allocation. EPA did not provide adequate supporting documentation to determine how these allocations were derived. [EPA-HQ-OAR-2009-0491-2745.1 p.4]
In a reversal in outcomes for NOx, Big Bend Station Unit 1 was allocated twice as many annual NOx allowances as Unit 2. As described above, these units were built during the same decade, have the same control equipment, the same limits, and operate with equivalent capacity factors. EPA did not provide adequate supporting documentation to determine how these allocations were derived. [EPA-HQ-OAR-2009-0491-2745.1 p.4]
Big Bend Station Unit 3 is listed in EPA's detailed data (see EPA technical support document "Budgets and Allocations - Detailed Unit-Level Data") as having zero heat input for 2008. This does not correlate to the "reported data" spreadsheet tab excerpted in Attachment A to these comments. Based on our discussions with Brian Fisher of EPA, this heat input value for Big Bend Unit 3 is inconsistent with the methodology and appears to be an error that likely impacts the modeling results.  [EPA-HQ-OAR-2009-0491-2745.1 p.4]
Although Tampa Electric understands EPA's motivation for using the model to allocate allowances, the results indicate that there are erroneous inputs or assumptions in the model. EPA did not provide adequate time or resources to determine the reason for these results, but the errors call the entire modeling process into question. Furthermore, the proposed allocation method penalizes those who have taken challenging and expensive early action to install controls. As noted in Section IV, below, we believe an allocation method utilizing heat input will avoid the potentially arbitrary and capricious result of rewarding inaction and penalizing those who have already installed controls. [EPA-HQ-OAR-2009-0491-2745.1 p.4]
Allowance Allocations Should be Based on Heat Input
Although it is conceivable that the IPM state allocations will meet the objectives of the Clean Air Act and Court ruling constraints, the lack of transparency, apparent errors, and inconsistencies make the proposed allocation scheme inappropriate. Therefore, we believe that individual unit allocations should be made based on heat input. The inventory of heat input data is robust, well vetted, and easily documented. We recommend that EPA use the following formula to calculate emission unit allowance allocations:
Emission Unit Allowance Allocation =
Where:
Emission Unit Allowance Allocations are the SO2, NOx annual, or NOx Ozone Season allowances provided each year for operation of the emission unit.
Emission Unit Heat Input (MMBtu) is the average of actual heat input of each emission unit in the program for each as compiled in CAMD Data & Maps (or EIA database) for years 2005-2009.
State Allowance Alloc. is the total amount of SO2, NOx annual, or NOx Ozone Season allowance provided each year to each State for operation of the emission units subject to the rule.
"N" represents the total number of emission units in each State subject to each respective program.
This alternative allocation methodology was described by EPA in the proposal (75 FR at 45311). Distribution of allowances based on heat input avoids arbitrarily rewarding those who did not install emission controls and avoids penalizing those who did install them. To continue with the proposed allocation method results in a disincentive for utilities to negotiate NSR agreements with EPA in the future. [EPA-HQ-OAR-2009-0491-2745.1 p.5]
Such an allocation methodology would not be prohibited under the dictates of the North Carolina v. Environmental Protection Agency decision because this relates to the per unit allocations within the EPA statewide allocation that is determined to be required to be met to address the nonattainment issues. This allocation method would not result in one upwind state sharing in the burden of reducing other upwind state's emissions, which the DC Circuit cites as the central deficiency resulting in the invalidation of use of fuel adjustment factor in the allowance allocation to the state. North Carolina v. Environmental Protection Agency @ p. 921. [EPA-HQ-OAR-2009-0491-2745.1 p.5]
EPA also requested comments on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the Title IV Acid Rain Program. Tampa Electric supports maintaining perpetual allocations to non-operating units because it would avoid the incentive of keeping an older unit operating to continue receiving allowances and it would simplify the administrative allocation process. [EPA-HQ-OAR-2009-0491-2745.1 p.6]
EPA also requested comments on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the Title IV Acid Rain Program. Tampa Electric supports maintaining perpetual allocations to non-operating units because it would avoid the incentive of keeping an older unit operating to continue receiving allowances and it would simplify the administrative allocation process. [EPA-HQ-OAR-2009-0491-2745.1 p.6]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.72-73.]
Tampa Electric would also like to take this opportunity to express its preference for utilizing EPAs alternative proposal to use the heat input-based allocation method, rather than the wholly emissions based ones.
Using heat input would likely result in less of an allowance shortage for those who made early emission reductions and help mitigate the referenced allocation errors. Tampa Electric, who as previously stated has a 50/50 split of natural gas and coal generation, has made significant investments in emission reductions.
I would like to use this as an example. For the year 2009, accounts for nearly 15 percent of the Florida state total heat input in for Acid Rain units, but only 5 percent of Florida's SO2 emissions.
Under the proposed Transport Rule allowance allocation, Tampa Electric may or may not have enough allowances to cover its current generation needs, even though $1.2 billion was spent to reduce emissions and fully control all units.EPA should not include Florida as a Group one state. Minimal contribution from Florida sources can be attributed to downwind states, CAIR controls have not been properly reflected in projected emissions, and other model input inaccuracies can account for greater variability in the models output than verifiable point source emissions contribution to nonattainment areas.
Response:
Thank you for your comment.Organization: Tennessee Valley Authority (TVA)
Comment:
Tennessee Valley Authority (TVA)
A. Issue: EPA proposes that once an EGU does not operate 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. After that seventh year the allowances would be allocated to the new unit set aside for the state. Other options EPA considered include continuing to allocate allowances for an unlimited period of time, or immediately discontinuing allocations to such units upon the unit ceasing operation. EPA seeks comment on the proposed approach for allocating allowances for non-operating units. [p. 45310- 11] [EPA-HQ-OAR-2009-0491-2782.1, pp. 14-15]
TVA Comment: Allowances to non-operating units should be allocated for an unlimited period of time. In this respect, non-operating units should be treated no different from units that reduce emissions by installing controls. Ending allocations for retired units could result in sub-optimal decisions, such as units electing to continue to operate units at very low capacity factors in order to retain their allocations. Moreover, in addition to the direct benefit of helping achieve and maintain the NAAQS for ozone and PM-2.5, the retirement of fossil units provide collateral environmental benefits such as the reduction in the emission of greenhouse gases. Therefore, EPA should continue to allocate allowances to non-operating units for an unlimited period of time and not discourage utilities from reducing emissions by retiring units. [EPA-HQ-OAR-2009-0491-2782.1, p. 15]