In the 2012 and 2014 IPM Parsed data Empire District's Riverton units 12, 39 and 40; Energy Center units 1, 2, 3 and 4; State Line units 1, 2-1 and 2-2 were incorrectly modeled with zero emissions.  In addition, the 2014 IPM Parsed data indicates retrofit controls for Riverton units 39 and 40, State Line units 2-1, 2-2, and 2-3 as "early retirement" of these units.  Empire District routinely evaluates its generation resources, existing and future, as part of its Integrated Resource Plan.  This Integrated Resource Plan is officially submitted to the state regulatory authorities having jurisdiction over Empire District once every three years.  Empire District submitted its most recent Integrated Resource Plan to the Missouri Public Service Commission in early September 2010.  In this filed report, all of the aforementioned units are reflected as operational in the 2012 and 2014 timeframe; in other words, Empire District's analysis shows that these units are still viable units to serve our customers in an economic and reliable manner under our current regulations and assumptions. [EPA-HQ-OAR-2009-0491-2659.1, pp.3-4]
Because of these reasons Empire District believes that the IPM parsed modeling data should be revised to correctly reflect the operation of these units in the years 2012 and 2014.  Empire District has provided in a separate electronic submittal to EPA's Rulemaking Gateway, Appendix C data file and cover letter.  This separate submittal contains information which we believe reflects the 2012 and 2014 operation of the emission units that Empire District owns and has an interest in ownership. [EPA-HQ-OAR-2009-0491-2659.1, p.4; for additional comments pertaining to corrections to the IPM data, see pp.4-5 of this comment summary]
Environmental Energy Alliance of New York, LLC
  EPA's Transport Rule analysis does not recognize the reductions already made in New York State. New York State implemented Part 237 and Part 238 to reduce acid deposition in New York State by limiting emissions of NOx from fossil fuel-fired electricity generating units during the non-ozone season and SO2 over the entire year starting on October 1, 2004 for NOx and January 1, 2005 for SO2. Both of these regulations were budget trading programs but because the programs were essentially limited to New York they required reductions within the State. Although at first glance it seems that the emissions in 2005 should reflect full implementation of the rules, there were early reduction credits that eased the transition into the program. Table 1 lists New York EGU EPA CAMD website emissions for all programs from 2002 to 2009 and includes the Transport Rule Q4 2008 to Q3 2009 emissions. As shown in the table, by 2007 the Part 237 and 238 programs had reduced the state-wide NOx emission rate and mass by 37% and SO2 rate and mass by 66% over the average emissions between 2002 and 2004. There was another round of reductions in New York State in response to the Clean Air Interstate Rule (6NYCRR Parts 243, 244 and 245) that are not fully reflected in the Transport Rule's Quarter 4 2008 to Quarter 3 2009 twelve month emissions; the NOx emission rates for calendar years 2008 and 2009 as well as the year-to-date 2010 are all lower. [EPA-HQ-OAR-2009-0491-2638.1, pp.1-2] [[See Docket Number EPA-HQ-OAR-2009-0491-2638.1, p.2 for Table 1.]]
The Alliance believes that the observed reductions in New York NOx and SO2 emissions shown in Table 1 are not correctly reflected in the Transport Rule base case. It is therefore, important that individual data used in EPA's analysis be corrected. One issue that has been raised is SO2 emission rate in oil/gas boilers when burning gas  -  it is not clear if a gas rate is used. The EEANY member companies will be submitting unit-specific comments to correct the input data. [EPA-HQ-OAR-2009-0491-2638.1, pp.2-3]
Our concerns with respect to the current modeling approach are illustrated in Table 1 which is a comparison of the 2012 base case projections for two different IPM modeling runs with recent historical data in Table 1 illustrate our concerns about the approach used. In response to issues raised with IPM V3.02 modeling results summarized in May 2010, another modeling analysis, V4.10 summarized in August 2010, was run. The Alliance believes that the average of the last three years of historical data is a good representation of typical conditions. The 2007 to 2009 average heat input of all New York sources reporting to CAMD was 653,403,662. The original IPM run was very close to that heat input but IPM V4.10 was only 478,786,000, a 27% decrease. Therefore, the more recent IPM analysis is projecting significantly less frequent operations than recent information and NY company projections would indicate. Although IPM V4.10 projects annual SO2 emissions very close to the recent historical data, the SO2 rate is 34% higher than observed. Nonetheless this is a huge improvement because the original run had the SO2 mass and rate 148% higher. The Alliance is especially concerned that both IPM runs project significantly lower NOx rates than observed. IPM V4.10 projects a 44% reduction in NOx rate from the observed 2007 to 2009 average of 0.106 to 0.059 as the 2012 base case. [EPA-HQ-OAR-2009-0491-2638.1, p.3]
The Alliance is primarily concerned that the Transport Rule rule-making process has increased the reliance on modeling analyses to determine not only the state allocations but also unit-specific allocations. The Transport Rule used the Integrated Planning Model to forecast future emissions in both a base case and a control scenario that provide the primary basis for the proposed rule-making. However, IPM predictions vary widely depending upon the assumptions (e.g., fuel price and control technology price and availability) used in a particular modeling run and there are inevitably site-specific discrepancies caused by the modeling approach which cannot be expected to consider every constraint at every facility. [EPA-HQ-OAR-2009-0491-2638.1, pp.3-4]
The Eastern Regional Technical Advisory Committee (ERTAC) is taking a different approach to develop and improve the emissions inventories used for projecting future emissions. ERTAC is evaluating an approach which grows base hourly EGU emissions into future projection years. It is expected that this approach will be more realistic and robust for this kind of analysis. The Alliance agrees that this is a preferable approach and encourages EPA to re-do this analysis with that approach or something else that does not rely on IPM for all future projections. [EPA-HQ-OAR-2009-0491-2638.1, p.4]
Therefore the Alliance recommends the following:
-That the process be revised to insure IPM base case modeling compares well with actual observed information. This is particularly indicative here because the Alliance believes that the base case modeling may not compare well with recent, actual observations and, thus, may not be a reliable representation of projected New York operations and emissions and cannot provide the basis for an appropriate control case;
-Incorporate steps to correct errors discovered in unit-specific information (member companies will be submitting specific comments in this regard);  [EPA-HQ-OAR-2009-0491-2638.1, p.4]
EquiPower Resources Corp.
EPA acknowledges the potential limitations on trading created by the Transport Rule's assurance provisions in the Rule's preamble, but dismisses them as not being an issue because "more units are likely to have allocations close to their [actual] emissions." However, this assertion is premised on the assumption that EPA's allocations were based on accurate information about a source's potential emissions. As explained in more detail in Section V.B below, EPA's unit-level allocations are not based on accurate assumptions; indeed, in many instances the assumptions are: (i) not readily apparent from the Agency's supporting documentation, (ii) directly at odds with other regulatory requirements, and/or (iii) simply incorrect. Therefore, EPA's assertion that sources will "have allocations close to their emissions" cannot be supported  -  and, in any event, relies on the unsupported assumption that unit utilization will remain static over time, as discussed above. For example, EPA has adjusted Phase I state-wide emissions, and by extension unit-level allocations, by its assumptions about the level of emissions control that individual EGUs achieve using existing controls or those that the Agency believes will be available by 2012. EquiPower does not believe that the Phase I caps reflect the level of emission reductions that are actually obtainable using existing controls or those that will be available by 2012. This is due to two types of erroneous assumptions made by EPA when making those budget adjustments. [EPA-HQ-OAR-2009-0491-2704.1, p.7]
First, EPA made assumptions about the level of control provided by existing controls which assumed that older, but still effective controls, obtained emissions rates that were equal to rates obtained by newly installed controls even though the Agency had (and should have used) data showing the actual level of performance achieved by those existing controls. The practical effect of this assumption is to penalize sources with older controls that have achieved substantial emissions reductions, but do not obtain the peak control rates that EPA assumes to be feasible. Moreover, EquiPower does not believe that EPA's assumed control rates for new controls are necessarily achievable on a sustained basis because they only reflect the level of control obtained when a unit is operating at peak capacity and do not reflect the level of control obtained during periods of start-up, shutdown, or non-peak operation that occurs throughout the year at most sources. [EPA-HQ-OAR-2009-0491-2704.1, p.7]
Second, and more glaringly, because of EPA's FIP approach, the Agency's allocations make inaccurate assumptions about existing controls or when new controls will be available. Most notably for sources in New England, and Massachusetts in particular, EPA has adjusted the 2012 SO2 budget for Unit 3 at Dominion's Brayton Point Power Plant by assuming that the unit's FGD will be online in 2012. However, EquiPower understands that construction of that FGD is not scheduled to begin until April 2011, and therefore that the FGD will not be in operation until sometime between the fall of 2013, at the earliest, and the first quarter of 2014. Unit 3 is the largest unit at Brayton Point, which in turn is the largest coal-fired power plant in New England. As a result, the Agency has seriously understated the level of emissions that will be produced by Brayton Point in 2012, and as a result has under-allocated its (and by extension, the entire state's) allowances. As a result, Brayton Point will likely buy up all of the excess SO2 allowances available in New England during Phase I to meet its needs, leaving no allowances for other sources that might need them. [EPA-HQ-OAR-2009-0491-2704.1, pp.7-8]
EPA Should Correct Errors In Its Allocations [EPA-HQ-OAR-2009-0491-2704.1, p.18]
The subsections below identify a number of erroneous assumptions about unit-specific characteristics in the Transport Rule that result in errors in both unit- and state-level SO2 and NOX allowance allocations. As explained below, these errors in EPA's data and assumptions with respect to EquiPower's facilities prejudice its unit-level allocations. Moreover, these errors show that EPA's data and assumptions are not in compliance with EPA's guidelines highlighting the Agency's "responsibility to ensure that the information is, and remains, accurate and credible." EquiPower requests that these comments regarding specific errors be considered a Request for Correction pursuant to EPA's Information Quality Guidelines, § 8.5. [EPA-HQ-OAR-2009-0491-2704.1, pp.18-19]
The Transport Rule's state emissions budgets and unit-level allowance allocations were based on the results of modeling which was intended to show the level of reductions required to assure that upwind sources of SO2 and NOX do not interfere with downwind attainment of specific air quality standards. Inputs into this modeling include assumptions about the (i) performance of new and existing controls and the resultant emissions reductions, (ii) projected capacity for individual units during Phase I and Phase II,(iii) type of fuel burned, and (iv) the maximum costs on a per ton basis for the required reductions. (For the Proposed Rule, EPA's cost thresholds were $2,000 and $500 per ton for SO2 and NOX, respectively).At the outset, EquiPower notes that the modeling tables provided by EPA are not transparent, making it difficult to track what assumptions have been made with respect to which units. Nevertheless, based on the assumptions that could be confirmed, EquiPower believes that EPA's allocation approach has not resulted in state budgets or unit-level allocations that are obtainable using either existing controls or those that EPA expressly identifies as being required based, in part, on flawed assumptions employed by the Agency. As explained above, EPA would have avoided these problems had it charged states with the responsibility of allocating allowances, as it is required to do under Title I of the CAA. In addition to these legal concerns, EquiPower believes that EPA has to make the following corrections to the assumptions it made with respect to EquiPower's facilities. [EPA-HQ-OAR-2009-0491-2704.1, p.19]
EPA Made Erroneous Assumptions about Unit Capacity Factors [EPA-HQ-OAR-2009-0491-2704.1, p.19]
Based on EquiPower's review of the available data, there appears to be a hidden unit capacity factor that EPA used in its state budget and unit-level allowance allocation calculations. Unfortunately, because of a lack of transparency in EPA's modeling tables, it is not possible to identify with precision the capacity factors used for specific units. Based on EquiPower's review of the allocations for its units, the Agency's capacity factor appears to have had a huge impact on the allocations for those units and has led to some readily apparent anomalies in the allowance allocations for each unit. [EPA-HQ-OAR-2009-0491-2704.1, p.19; for additional comments pertaining to EPA Made Erroneous Assumptions about Unit Capacity Factors, see pp.19-22]
EPA Made Inaccurate And Inconsistent Assumptions About The Performance Of Existing Controls At Different Units [EPA-HQ-OAR-2009-0491-2704.1, p.24]
In addition to the capacity factor errors and failure to account for dual fuel operations, EPA's modeling also contained inaccurate and inconsistent assumptions about the performance of emissions controls at EquiPower's facilities and at other facilities in New England. The most notable example of this kind of omission is EPA's error with respect to Brayton Point 3's FGD. As explained above, EPA assumed that the FGD would be available in 2012 to meet the Phase I emission caps; however, EquiPower understands that construction of that FGD will not start until 2012 and that it will not be available until 2013 or later. Because of the size of the Brayton Point plant and EPA's chosen methodology for calculating state budgets and allocating allowances, this error has a material impact on sources in New England and will necessarily constrain the availability of SO2 allowances in New England. A fundamental error like this must be corrected before the Proposed Rule is finalized and could have been avoided had states been charged with establishing allocations as required by the CAA. [EPA-HQ-OAR-2009-0491-2704.1, p.24]
In addition to these basic errors, EPA appears to apply its assumptions inconsistently. For example, EquiPower's Lake Road Facility in Connecticut is functionally identical to another facility located in Connecticut (Milford Power); both units have the same capacity, use the same equipment and provide roughly the same heat input based on data reported by sources to EPA. However, EPA's allocations for the two units are materially different. Despite their similarities, the Lake Road Facility's allocations are basically half of Milford Power's. The basis for this disparity in allocations appears to be EPA's application of a much less stringent emissions rate assumption on the Milford Power facility. See Table 6. [See p.24 of this comment summary for Table 6] Given that these facilities are identical, the Milford Power facility's allocations should track those at the Lake Road Facility. [EPA-HQ-OAR-2009-0491-2704.1, p.24]
In Addition To The Various Unit-Level Errors, EPA Also Has To Correct Its State-Level Emission Budgets [EPA-HQ-OAR-2009-0491-2704.1, p.25]
EquiPower believes that the errors identified above call into question EPA's assumptions and modeling. For example, according to the Agency, the reductions required during Phase I of the Transport Rule are only supposed to require that the status quo be maintained (i.e., the Phase I reductions are those that are available from emissions controls that either currently exist  -  e.g., running current SCRs year round  -  or those that are in the pipeline and will be available by 2012). Based on the errors identified above, it is unclear how that can be the case because the Agency's modeling does not capture the status quo accurately. As a result, EquiPower believes that the Agency needs to correct the various unit-level errors identified above, or raised by any other party, and then revisit its state-level emissions budgets so that they too can be corrected. [EPA-HQ-OAR-2009-0491-2704.1, p.25]
Exelon
Exelon has reviewed relevant technical support documents relating to EGU emissions and allowance allocations, and has the following additional comments on specific issues regarding Exelon's facilities. [EPA-HQ-OAR-2009-0491-2666.1, p. 44; for additional comments on specific issues regarding Exelon's facilities in the Technical support documents, see pp.44-45 of this comment summary]
Exelon recognizes that EPA continues to refine its modeling and will continue to refine its allowance allocations. Indeed, Exelon urges EPA to adopt an allowance methodology that avoids issues such as these that arise from modeling exercises, and instead to adopt the allocation methodology discussed above. In the event that EPA does not adopt a more verifiable allocation methodology, Exelon urges EPA to correct the allocations of allowances to these units, based on the information provided herein. Exelon continues to investigate various anomalies in EPA's IPM modeling and emission allocations to certain types of units and in certain states. This discussion may provide further basis for additional technical comments, which Exelon may submit in connection with the NODA. [EPA-HQ-OAR-2009-0491-2666.1, p. 45]
First Energy
In support of the comments above, please see Appendices A and C [See p.12 (Appendix A) and 24 (Appendix C) of this comment summary] for details regarding the modeling completed by Alpine Geophysics on behalf of MOG. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2]
Construction Assumptions & Time Schedules
The EPA has extremely aggressive assumptions built into their control equipment construction timelines that FE believes to be so extremely optimistic that they are infeasible. Specifically, the EPA referenced construction and installation schedules for a scrubber at 27 months and an SCR at 21 months. FirstEnergy just completed a complex scrubber and SCR retrofit project at our Sammis Plant earlier this year, driven by an aggressive schedule in a Consent Decree with the EPA. This scrubber and SCR installations at the Sammis Plant required 58 months from initiation of project engineering to construction completion. See Appendix B for two pictures that will illustrate the magnitude and complexity of this retrofit project. [EPA-HQ-OAR-2009-0491-2657.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2657.1, p.27 for Appendix B.]]
Additionally, the 27 month scrubber installation assumption does not accommodate a coordinated schedule to site, permit and construct a landfill to accept the waste generated by the scrubber. FirstEnergy needed nearly five years to site, permit and construct a landfill to allow Sammis Plant scrubbers to begin operation. Likewise, FE has also recently installed SNCR's which required from 12 months to 18 months, compared to EPA's unrealistic assumption. Actual, recent experience by FE invalidates the EPA's schedule assumptions for control equipment installations. [EPA-HQ-OAR-2009-0491-2657.1, p.5]
Additionally, the number of major construction projects required by CATR will stress the capability and capacity of 1) architect/engineering firms, 2) shop space for major components, and 3) the skilled labor force required over the duration of a major construction project. FE experienced skilled labor shortages during the R.E. Burger SNCR installation in May 2008. Scrubber outages within AEP and FE impacted the available supply of certified welders at R.E. Burger. Granted this was a small project relative to scrubber and SCR installations, but it highlights the potential labor impact if utilities immediately ramp up major construction projects between 2012 and 2014. Couple the unavoidable increase in project construction for CATR compliance with the likely compliance requirements for the EGU MACT, and the available resources necessary for project completion will vanish. Given the potential impact of prolonged construction schedules, FE recommends that, at a minimum, EPA include a mechanism for compliance delay approvals in CATR. [EPA-HQ-OAR-2009-0491-2657.1, pp.5-6]
EPA needs to modify its very aggressive and unrealistic assumptions to reflect actual experience at real-world retrofit locations, which suggests that the Phase 2 deadline in CATR  -  if the rule is indeed still needed - should be pushed out until at least 2016. [EPA-HQ-OAR-2009-0491-2657.1,p.6]
Low NOx Burners (LNB)
The EPA assumes the engineering, modeling, procurement, and installation of low NOx burner (LNB) technology can be completed within six (6) months. Individual burner design is highly site specific and it is incorrect to assume that LNB manufacturers have an abundant supply of universal LNB's available for utilities to purchase off the shelf. FE has installed LNB's on a broad cross-section of its boilers. Following initial design and procurement which typically take 4 months, the duration between awarding the project until the material arrives on site is typically 8-9 months. Burner installation then needs to be coordinated with a scheduled boiler outage, which typically has a 6 to 8 week duration. Based on the duration of these activities, a typical LNB installation is 18 months  -  assuming it can be lined up with an appropriately timed boiler outage. [EPA-HQ-OAR-2009-0491-2657.1,p.6]
Finally, prudence dictates that a Company will not commit to a major capital improvement like a LNB, scrubber or SCR installation until final rules are issued. Therefore if the CATR is issued as a final rule in June of 2011, this leaves only 30 months to complete a significant number of complex capital projects across a large number of facilities before the proposed Phase 2 deadline of January 1, 2014. As stated earlier, there are also the very real physical and logistical limitations on resources including engineering, materials, shop space and skilled labor which - based on past experience  -  limit the capacity of the industry to complete multiple projects in the same region simultaneously. [EPA-HQ-OAR-2009-0491-2657.1, p.6]
Cost Assumptions
FE does not agree with EPA's capital cost assumptions ($/kW) for scrubber installations. FE capital cost experience at WH Sammis for a 2005-2010 Scrubber installation with a multi unit configuration (2-vessels, 840 GMW/vessel) was between $340 and $360/kW. The remaining WH Sammis scrubber for Sammis Units 1-4 (192 GMW each) was between $470 and $490/kW. The EPA data unrealistically assumes a cost range of similar scrubber size from $182 to $215/kW. This understates the capital cost by as much as 250%. Similarly, the EPA unrealistically assumed O&M costs ($/kW) that are only half of FE's actual O&M cost. Since model outputs are based on these incorrect EPA assumptions, FE recommends the EPA correct the IPM input data to reflect real world installation and operating costs. The EPA should re-run the IPM model cost curves, re-determine each state's "Significant Contribution," revise state allocation totals for NOx and SO2, and correct the individual unit allowance database. [EPA-HQ-OAR-2009-0491-2657.1, pp.6-7]
FE also does not agree with EPA's capital cost assumptions ($/kW) for SCR installations. FE capital cost experience at WH Sammis for a 2005-2010 SCR installation for WH Sammis Units 6&7 was between $220 and $250/kW. The EPA data unrealistically assumes a cost range on a similarly sized unit at $169/kW. [EPA-HQ-OAR-2009-0491-2657.1,p.7]
General NOx reduction assumptions relative to industry and FE units
The 90% SCR NOx reduction applied to the NEEDS data by the EPA does not reflect typical industry experience. A 90% removal efficiency is exceedingly difficult and rare to achieve on a long term annual basis as performance degrades due to SCR fouling, catalyst deactivation and system reliability. Based on 2009 CAMD data from 224 units, SCR NOx removal efficiency for the industry averages just over 80%. [EPA-HQ-OAR-2009-0491-2657.1,p.7]
Control equipment performance and removal efficiency assumptions need to account for actual individual unit performance under day-to-day operating conditions, not a performance guarantee removal efficiency provided by a vender based on one-time short term tests conducted immediately after a control device is commissioned. For pre-CAIR SCR's, typical performance assumptions were designed to and based on seasonal operation, not annual operation. EPA's SCR NOx reduction assumption does not reflect real world operation where SCR's foul and catalyst deactivates resulting in control equipment performance degradation over time. [EPA-HQ-OAR-2009-0491-2657.1, p.7; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6 10/15/2010]
Likewise, deeply staging combustion with low NOx burners to drive down furnace NOx results in a reducing atmosphere in the furnace, significantly shortening boiler tube life and increasing outage O&M and capital costs. Operating in an oxygen deficient atmosphere to reduce NOx also has the side effect of increasing carbon content in the ash and soot emissions from the boiler, resulting in a very difficult balancing act between minimizing NOx emissions and maintaining particulate compliance. This fact does not appear to be addressed in the EPA's analysis. [EPA-HQ-OAR-2009-0491-2657.1,p.7; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6 10/15/2010]
Sergeant and Lundy SNCR Cost Estimate data sheets for NEEDS referenced a 25% NOx reduction for their cost model. The EPA uses a 35% reduction in the utility NEEDS data which is not representative of real world performance over the boiler operating range. In order to improve the data accuracy, the SNCR removal efficiency assumptions should be corrected from 35% to 25%. [EPA-HQ-OAR-2009-0491-2657.1,p.7]
Fuel Switching Assumptions
Fuel switching is an alternative identified by the EPA to reduce SO2 without installing Flue Gas Desulfurization (FGD). The EPA states in the preamble to the rule that particulate emissions will likely increase due to the increased use of low sulfur, Powder River Basin (PRB) fuel. Increasing emissions is directly related to the electrostatic precipitator's decreased collection efficiency relative to the sulfur content of the PRB along with the increased volume of flue gas. The EPA should include the capital investment required to maintain good ESP performance in the cost assumptions. ESP's that will underperform with low sulfur fuel may require flue gas conditioning systems, upgraded power supplies, and/or total rebuild of the particulate control equipment. These costs are highly variable by unit and installation, but are typically in the $25-50/kW range. [EPA-HQ-OAR-2009-0491-2657.1,pp.8-9; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7 10/15/2010]
The EPA further assumes any unit capable of burning a blend of PRB can burn 100% PRB without issue. This assumption is grossly inaccurate. In is FE's experience that units switching to 100% PRB are invariably assigned a fuel derate. A unit may be able to blend PRB with bituminous fuel to achieve NDC, but each boiler would have a unique blending level and derate. Typically, the derate is related to the significant drop in Btu's in the PRB fuel vs. typical eastern fuel (approximately 30% less Btu's in PRB) and limitations with increasing the volume of fuel feed and air flow to make up for the lower heat content of the PRB substitute. [EPA-HQ-OAR-2009-0491-2657.1, p.9]
On the other hand, the IPM model should also account for improved NOx emissions on units switching to 100% PRB. Typical PRB fuel bound nitrogen is ~0.8% while bituminous fuel bound nitrogen is ~1.0 to 1.2%. IPM should also account for the improved NOx emissions when considering fuel switching as an option to control SO2 emissions. [EPA-HQ-OAR-2009-0491-2657.1,p.9]
The EPA's assumption that multiple units can switch to 100% PRB without significant capital cost at a facility does not account for the necessary fire protection, dust suppression, mill adjustments and coal pile reconfiguration required to accommodate firing PRB fuel. [EPA-HQ-OAR-2009-0491-2657.1, p.9]
Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10
On page 3-3.7, the statement made regarding the Ohio Edison Consent Decree (CD) for a NOx limit on Sammis Unit 6 & 7 `Operate to the minimum extent practical' is incorrect. The Sammis NOx rate in the Sammis CD is 0.100 lb/mmBtu on a 30-day rolling average (Page 18 of the Consent Decree). Additionally, the CD requires NOx emissions reductions from Eastlake Unit 5 and Burger Boiler 7&8. Eastlake Unit 5 must accumulate an 11,000 ton reduction from 2003 levels. Burger 7&8 must accumulate a 1,400 ton reduction from 2003 levels (Page 13&14). These additional reduction requirements would have an impact to the IPM runs since they require continuous operation of the installed pollution controls. Additionally, Eastlake 5 & Burger 7&8 have a reduction requirement based on Heat Input. Modeled heat input reductions on EL5 and/or Burger 7&8 would make compliance with the CD difficult. [EPA-HQ-OAR-2009-0491-2657.1, p.11; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11 10/15/2010]
In general, the EPA makes assumptions that do not relate to required operations on specific Units. FE recommends the EPA correct ALL utility data to reflect accurate model inputs. [EPA-HQ-OAR-2009-0491-2657.1,p.12; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11 10/15/2010]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA's imposition of a 2012 compliance obligation is unreasonable and unrealistic, particularly since EPA intends to finalize the rule less than six months before it becomes effective. EPA attempts to dismiss this burden, however, by claiming that the emission levels required in 2012 generally reflect only the emission reductions that would occur even in the absence of the Transport Rule, primarily in compliance with CAIR. However, in a number of cases EPA has made incorrect assumptions regarding emission reductions that will occur at units by 2012. In addition, the approach set forth in the proposed Transport Rule penalizes early emission reductions under CAIR and seriously weakens market incentives. [EPA-HQ-OAR-2009-0491-2658.1, p.2]
FCG members have noticed multiple errors in EPA's 'Unit Characteristic' spreadsheet and other spreadsheets which were utilized to base future reductions per this rulemaking, e.g., unit pollution control equipment in place and operating. In some cases, the pollution control device which is not listed in the spreadsheet has been installed for multiple years and is required to operate in order to meet State permit specific emission limits. [EPA-HQ-OAR-2009-0491-2658.1,p.9]
As stated above, FCG members will be sending comments on an entity-specific basis regarding the needed changes to EPA during this comment period. The FCG, however, is concerned that it will be deprived of an opportunity to comment after EPA makes the necessary corrections to their dataset. In sum, EPA will need to perform additional modeling and calculations after corrections have been made to many regulated units, and such changes will be substantial enough to warrant an additional notice and comment period. The correction of these extensive errors will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, and parties can meet their new compliance obligations. [EPA-HQ-OAR-2009-0491-2658.1,p.10]
Florida Municipal Power Agency (FMPA)
5. In EPA's proposed allowance Allocation Table, Cane Island (ORIS Code 7238) Units 2 and 2A have improperly received separate allowance allocations, as have Cane Island Units 3 and 3A. In EPA's Technical Support Document "State Budgets, Unit Allocations, and Unit Emissions Rates", EPA states, "In cases where one unit with reported emissions matched to multiple units in the IPM/NEEDS inventory, emissions were divided equally." Cane Island Units 2A and 3A are the bypass stacks for Cane Island Units 2 and 3, respectively. Prior to EPA's adoption of XML format reporting for 40 CFR 75 Electronic Data Reports (EDR's), these units reported emissions separately for the main and bypass stacks. This is probably why they are listed as separate units in the IPM/NEEDS inventory, which led to EPA's dividing of the emissions. Reporting of emissions at the overall unit level has been required since EPA changed to the XML EDR format in first quarter 2009, therefore, reported emissions from Units 2 and 3 now include the emissions from bypass stacks 2A and 3A. In order to align RTR allowance allocations with 40 CFR 75 reporting requirements for these units, FMPA recommends that the sum of the allowances allocated to Units 2 and 2A and the sum of the allowances allocated to Units 3 and 3A be allocated to Units 2 and 3, respectively. [EPA-HQ-OAR-2009-0491-2725.1, p.7]
Four Flags Area Chamber of Commerce
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions - the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-3807, p.2]
George Washington University Regulatory Study Center
Second, there is also likely model uncertainty associated with developing these estimates. For example, EPA uses its Integrated Planning Model (IPM) to develop projections of baseline emissions in 2012. EPA also used IPM modeling in the 2005 CAIR rule to project future emissions through 2015. As it turns out, emission reductions since CAIR was published in 2005 have exceeded the IPM projections for the CAIR rule. As the EPA puts it, "Substantial emissions reductions have occurred as a result of the CAIR programs. These reductions are greater than were expected when the rule was promulgated." [EPA-HQ-OAR-2009-0491-2573.1, p.23]
Georgia Department of Natural Resources, Air Protection Branch
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.92.]
A specific example is that EPA has modeled approximately 551,000 tons of SO2 in 2012, while the modeling inventory for our PM 2.5 SIPs that have been submitted to EPA use approximately 233,000 tons of SO2 in 2012. Clearly more than doubling the emissions would grossly misrepresent Georgia's impact on non-attainment or maintenance areas in other states.
Giarmarco, Mullins & Horton, P.C.
Below, MCV provides information to address what it believes to be incorrect emissions model assumptions resulting in erroneous unit-specific projections generated by the IPM model in support of the Proposed Rule and as contained in the 'Budget and Allocations - Detailed Unit-Level Data' spreadsheets. This information was reviewed in conjunction with EPA's Notice of Data Availability dated September 1,2010 and may be further commented on by MCV as allowed under that notice. [EPA-HQ-OAR-2009-0491-2766.1, pp1-2]
- The 2008 Reported Annual Heat Input figures appear to be accurate when observed collectively, however specific unit figures do not match MCV reported records. In particular, the heat input values for Units GT8, GT9 and GT3 are 50% of the values reported by MCV. EPA then appears to account for the 50% shortfall of Units GT8, GT9 and GT3, by assigning an equivalent value to BP15, ST1, and ST2. MCV believes that Units BP15, ST1, and ST2 should be zero. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- The 2009 Reported Annual Heat Input figures appear to be accurate when observed collectively, however specific unit figures do not match MCV reported records. In particular, the heat input values for Units GT8, GT9 and GT3 are 50% of the values reported by MCV. EPA then appears to account for the 50% shortfall of Units GT8, GT9 and GT3, by assigning an equivalent value to BP15, ST1, and ST2. MCV believes that Units BP15, ST1, and ST2 should be zero. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- MCV believes that the balance of all reported unit-specific heat input and mass data as reflected on the 'Reported Data' spreadsheet, suffers from the same errors identified in the preceding two paragraphs. Use of this data appears to produce erroneous IPM modeling results throughout the MCV data set as exemplified in the allocation of emission allowances to the two steam turbines. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- The projected emissions and corresponding heat input values appear to be the result of incorrect assumptions that MCV gas-fired units are operated relatively infrequently as peaker units. This is incorrect, as MCV operates its unit as a base load plant. MCV believes that the projected ozone total is 100X less than its expected use. Further, MCV believes the projected annual total is at least 20X less than expected use. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- MCV is unable to determine the genesis of the 'adjusted for controls and heat input figures assigned to all of its units. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- The projected annual and ozone NOx emission rates are inconsistent with expected emissions. The identified ozone NOx emission rates appear to be overstated by a factor of 10X, while the annual NOx emission rates appear to be understated by a factor of 10X. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
Gulf Coast Lignite Coalition
EPA Should Rely on Historical Data Rather than the Integrated Planning Model (IMP). [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
The IPM inputs are based on flawed assumptions regarding the electric generating units' fuel sources, ability to switch fuels, and operational longevity. GCLC questions how allowance allocations and emission budgets can be based on speculative assumptions rather than historical data. [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
To prevent any public notice concerns and the promulgation of a final Transport Rule based on flawed assumptions, the EPA should issue a Supplemental Proposed Transport Rule based on historical data, and issue a revised Regulatory Impact Analysis, allowing the public an opportunity to comment, before promulgating a final Transport Rule. [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
Indiana Builders Association
The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-2871.1, p.1]
Power companies in Indiana inform us that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. The home builders in our membership will have to bear a financial burden that may be unneeded. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-2871.1,p.2]
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-2871.1, p.2]
Indiana Cast Metals Association (INCMA)
The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
Power companies in Indiana inform us that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. The foundries in our membership will have to bear a financial burden that may be unneeded. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
Indiana Energy Association
b. An example of the technical errors in the EPA CATR analysis is that EPA assumes that since EGUs have been able to construct scrubbers and SCRs in a specific number of months in the past, that schedule will work for future controls at all plants . While that assumption may have technically worked for CAIR controls, CAIR included widespread regional emissions trading and multistate emission caps. The proposed CATR has state-specific caps resulting in companies being more reliant on in-state focused compliance and therefore making emissions trading far less likely and marginally more costly . That means that many sources in individual states will not be able to install controls in the timeframe the EPA has assumed is reasonable . EPA has provided no technical analysis for each individual state supporting its conclusion that individual state sources will be able to meet the required pollution control installation implementation dates. This is especially true in a state like Indiana, which is more dependent on coal-fired generation than virtually any other CATR state and where units have multiple characteristics that are not similar to other states in which a few large units have been able to construct controls . The Indiana Utility Group therefore believes that, in order to reflect the real world of EGU operations, each state's potentially affected sources will have to be analyzed separately for the final rule in order to determine a realistic compliance schedule for units in each state . [EPA-HQ-OAR-2009-0491-3711 p.2]
Indiana Manufacturers Association, Inc. (IMA)
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
The IMA encourages the EPA to delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to Indiana. [EPA-HQ-OAR-2009-0491-1813.1, p.1]
Reasons to delay include: The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
Power companies in Indiana estimate the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. Industry in Indiana will have to bear a financial burden that may be unneeded. [EPA-HQ-OAR-2009-0491-1813.1, p. 2]
Louisiana Public Service Commission
The LPSC Staff believes that the baseline generation data and modeling utilized by the EPA in formulating its NOx allocations is flawed and leads to results entirely inconsistent with the current and anticipated dispatch of Louisiana's EGUs. The expedited time period for analysis and comment has restricted the LPSC Staff's ability to develop a strong item-by-item critique of the EPA's baseline data and assumptions, much less the dispatch modeling and its underling algorithms. [EPA-HQ-OAR-2009-0491-2670.1, p.7]
The LPSC Staff first notes that a fundamental shortcoming in the EPA dispatch analysis rests with its assumption that no regional transmission constraints exist. Anyone familiar with the bulk power system in South Louisiana understands that the state's unique geography, coupled with limited transmission capacity along certain strategic transmission line segments, results in a number of transmission bottlenecks in the area west of the Atchafalaya Basin ('WOTAB'), as well as the area leading into the greater New Orleans area. 1 There are also considerable constraints limiting the flow of power from north of WOTAB into the greater Acadiana region of the state. During certain periods of the year, the constraints in the central part of the state limit the use of base load generation that can be transported from the coal units subjected to the CATR to the loads in greater Lafayette region. [EPA-HQ-OAR-2009-0491-2670.1, p.7]
Bulk power systems are generally operated and 'optimized' on a principle of 'economic dispatch' subject to reliability constraints. In other words, least cost generators are utilized in any given hour to meet load requirements, provided those units can be dispatched economically and reliably, and the capacity to transport that capacity is available. Transmission constraints however, can necessitate the utilization of higher cost, more localized units to replace (not displace) lower cost generation blocked by the constraint. Commonly constrained areas are often referred to as 'load pockets,' and the uneconomic dispatch required to serve the loads in these load pockets is referred to as 'out-of-order' dispatch. The localized units used to meet these requirements are referred to as 'regulatory must-run' ('RMR') generators. [EPA-HQ-OAR-2009-0491-2670.1, p.8]
RMR generators are often utilized in Louisiana to overcome transmission constraints in the state's three main load pockets. RMR units can also be used to meet voltage, balancing, and regulation support (generally, 'reactive power' requirements) that are important in maintaining system stability and reliability. The EPA model entirely ignores the challenges of Louisiana's bulk power system and as such, leads to a variety of erroneous allocations for individual EGUs. [EPA-HQ-OAR-2009-0491-2670.1, p.8]
Allocations Not Consistent with CAIR. The LPSC Staff has provided a number of preliminary analyses comparing the allocations provided for under CAIR, and those provided for under the CATR. The comparisons are incremental to CAIR, and should not be interpreted as the total cost of compliance with overall NOx and SO2 compliance costs. Schedule LPSC-2 provides a summary comparison of the NOx allocations under CAIR and CATR by major EGU operator and fuel type, while Schedule LPSC-3 provides a unit-specific comparison of NOx allocations. Schedule LPSC-4 provides similar high-level comparisons for SO2 allocations for major EGU operator and fuel type, while Schedule LPSC-5 provides comparable information on a per EGU basis. [EPA-HQ-OAR-2009-0491-2670.1, pp.8-9]
[For additional comments pertaining to this topic, see pages 9-13 of this comment.]
The LPSC Staff appreciates the opportunity to comment on the proposed CATR. The LPSC Staff has serious reservations about the approach, methods and data that EPA utilized in determining its recommended NOx allocations for Louisiana's EGUs. The LPSC Staff is exceptionally concerned that EPA's current proposals could create considerable negative rate impacts for many Louisiana utility customers. The LPSC Staff recommends that the EPA revise its modeling and analysis and submit a revised rule with a meaningful comment period that provides parties with sufficient time to review the policy proposals and the empirical support underlying those proposals. However, if the EPA continues to move forward with its current proposals, the LPSC Staff recommends a NOx allocation based on the same per-unit proportions that was created under CAIR. This allocation has been provided in Schedule LPSC-7. [EPA-HQ-OAR-2009-0491-2670.1, p.15]
[Schedules can be found at the end of the comment.]

1. Referred to as the Amite South transmission control region. [EPA-HQ-OAR-2009-0491-2670.1, p.7]
Luminant
The baseline modeling for ozone does not appear to include EGU emission reductions in the Houston area, which may affect the outcome on Baton Rouge predictions. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
Madison Gas and Electric Company (MGE)
We have reviewed the Proposed Rule along with the Technical Support Documents, including the proposed unit allocations, and have the following comments regarding proposed allocations to MGE-owned units. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
:: There is a plant named 'Diesel Generators' in the Allocation Table with Office of Regulatory Information Systems (ORIS) No. 56070, which is listed as a combustion turbine having a capacity of 44.1 megawatts (MW). This entry refers to 54 separate diesel generators owned by MGE, with capacities ranging from 878 to 2,500 kilowatts (kW) each. Although no allocations were given to the Diesel Generators, this entry should be removed from the Allocation Table and any subsequent analysis to be completed for the Final Transport Rule. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
:: Fitchburg Generating Station, Units 1 and 2, with ORIS No. 3991 are included in the Allocation Table even though the capacities of each unit are less than 25 MW. Although no allocations were given to either unit, they should be removed from the Allocation Table. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
:: West Campus Cogeneration Facility (WCCF) units listed as Unit 1, CT2, and STG1 with ORIS No. 7991 are included in the Allocation Table and should be removed because WCCF meets the exemption for cogeneration facilities. WCCF is not currently subject to the Clean Air Interstate Rule and will continue to meet the criteria for exemption from the Transport Rule. Each unit was given a small number of nitrogen oxide allocations in the proposed Allocation Table. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
Marquette Board of Light and Power
Inaccurate Project Control Technology
The EPA inaccurately projected that an SNCR would be installed on Shiras Unit 3 to meet the requirements of the Clean Air Interstate Rule (CAIR). However, due to the already low average NOx emission rate of 0.150 lb/mmBtu, the projected control technology to be installed is more highly efficient low NOx burners that would have achieved the Phase 2 CAIR requirement of 0.125 lbs/mmBtu. The estimated cost to install an SNCR on Shiras Unit 3 is approximately $2,000,000. To achieve the approximate 100 ton reduction required by the Transport rule would amount to spending $20,000/ton of NOx removed. This is well above the EPA established average cost-effectiveness of $2,000/ton of NOx removed (pg 45231 of Federal Register). By not taking into account facilities that already have much lower than average emission rates, this rule offers a competitive advantage to high NOx emitters while ensuring low emitters will be captive to either a market trading system or forced to offset emissions with smaller (less efficient and a higher emitter of pollutants) combustion units with less stringent emission controls. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Michigan Manufacturers Association (MMA)
Third, EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Minnesota Power
Unit level data and budget calculation discrepancies. Several Minnesota generating units are presented by EPA with little or no budget allocations. It was noted in the Minnesota Power Transport Rule comments that the M.L. Hibbard Energy Center Units 3 and 4 were not included in EPA's unit allocations listing. The Taconite Harbor Energy Center Unit 3 budget calculation and IPM modeling emissions appear to reflect controls not scheduled for installation until after EPA approves the Minnesota regional haze SIP, BART eligible unit measures. Minnesota Power also observes that EPA formula calculations that consider historic and permitted emission rates do not appear to be applied consistently from unit to unit.  There are apparent discrepancies between actual permitted emission rates, NEEDS posted permitted emission rates and emission rates selected by EPA for unit level budget allocations that might be explained by variations in reference year timing but that is not certain.  EPA needs to provide information that explains the basis for budget allocations and emission projections on a unit specific basis such that a regulated party can replicate the calculation using consistently and clearly defined measures.  This is needed to allow parties proposed for regulation to develop a sense of proposed control obligations suitable for providing EPA with comments or to cite the need for corrections.  [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.4]
Correction review time before rule finalization. If EPA corrections in proposed Transport Rule data inputs or modeling design are made, as EPA indicates will be the case, EPA should offer those changes for public review and comment for technical correctness before EPA finalizes the Transport Rule. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.4]
Access to emission allowances needed for compliance.  The IPM model appears to presume that a unit in operation will be able to obtain emissions allowances necessary for compliance by paying EPA's model estimated allowance price.  EPA has not clarified what a unit operator is to do to continue operations if their budget allocations are insufficient to support designed or intended electricity production and no Transport Rule allowances are available for purchase.  All units accredited for dispatch should have a means by which they can provide for compliance with their Transport Rule budget. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.4]
Mirant Corporation
3. In any event, it is inappropriate to use the Integrated Planning Model (IPM) as a basis for issuing allowances to individual units. Although IPM is an impressive and useful analytical tool, it was not designed to serve this purpose and has been shown to be inaccurate in making unit-level projections. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
4. Regardless of how IPM is used, it contains a number of inaccuracies that must be corrected before it can be used for decision-making. Among other things, it appears that IPM does not properly incorporate the requirements of the Healthy Air Act and does not reflect what actually happens with relatively high-cost units that serve a key role in many markets. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
III. It is Inappropriate and Unnecessary to Use the Integrated Planning Model (IPM) as a Basis for Issuing Allowances to Individual Units
The Integrated Planning Model (IPM) is a macro-level modeling tool that was not designed to predict emissions from particular emission units. In the proposed rule, however, EPA has used the results of IPM modeling runs not only to predict unit-specific emissions, but also to allocate very valuable emissions allowances to specific units. This is puzzling when there are well-accepted methods for making allocation decisions based on heat input. Although the CAIR court was troubled by the fuel adjustment factor that EPA used in CAIR, the Court certainly said nothing to suggest that it was not proper to use heat input. Again, Mirant urges EPA to make allowance decisions based on historic heat input, which is well-known for each unit, rather than modeling runs of projected future emissions  -  projections that are highly uncertain at the unit level. [EPA-HQ-OAR-2009-0491-2843.1, p.8]
EPA describes IPM as 'a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting energy demand and environmental, transmission, dispatch, and reliability constraints. Among the factors that make IPM particularly well suited to model multi-emissions control programs are (1) its ability to capture complex interactions among the electric power, fuel, and environmental markets; (2) its detail-rich representation of emission control options encompassing a broad array of retrofit technologies along with emission reductions through fuel switching, changes in capacity mix and electricity dispatch strategies; and (3) its capability to model a variety of environmental market mechanisms, such as emissions caps, allowances, trading, and banking.' EPA website, http://www.epa.gov/airmarkt/progsregs/epa-ipm/historicalmultip.html. [EPA-HQ-OAR-2009-0491-2843.1, p.9]
Although IPM is certainly detail-rich with respect to emission control options, it is not detail-rich with respect all the individual EGUs in the country. In the proposed Transport Rule, EPA has translated the market predictions within IPM into hundreds of millions of dollars worth of allowances. It is inappropriate and unnecessary to use IPM for this purpose. [EPA-HQ-OAR-2009-0491-2843.1, p.9]
Mirant is aware of several examples of the problems created by EPA's proposed approach, although it is not clear whether these problems were created by the model itself or by model inputs. First, Mirant operates two large coal-fired units at its Morgantown plant. They are sister units built at the same time, and they were both retrofitted with identical scrubbers that began operating in December 2009. Yet IPM predicts that Morgantown Unit 1 will operate with an SO2 rate of 0.068 lbs/mmBtu, and Unit 2 will operate with an SO2 rate of 0.141 lbs/mmBtu. As a result, Unit 1 receives only 1,482 SO2 allowances, whereas Unit 2 receives 3,004 allowances. [EPA-HQ-OAR-2009-0491-2843.1, p.9]
Even more troubling is the disparate treatment of the two Morgantown units compared to Constellation's two Brandon Shores units, which also have scrubbers that were installed in response to the HAA and started operating about a month or two later than the Morgantown scrubbers. The projected SO2 emission rates for, and the corresponding SO2 allowances that would be given to, each of the units is shown below:
[The table pertaining to the SO2 units can be found on page 9 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.9]
The projected NOx emission rates are also unexpectedly different  -  both Brandon Shores units are at 0.08 and both Morgantown units are at 0.06. Under the proposed rule, the units with the higher predicted rates would be rewarded with more NOx allowances as well. Mirant does not understand what gives rise to these projected differences among similarly situated units. [EPA-HQ-OAR-2009-0491-2843.1, p.10]
We recently identified another puzzling anomaly involving the way that NOx allowances would be allocated to small units in Southeastern Massachusetts under the proposed Transport Rule, as shown in the following table.
[This table can be found on page 10 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.10]
Although it involves a relatively small number of allowances, we do not understand why Kendall Square 4 would receive less than 1/10th of the number of allowances given to nearby units that appear to be very similar. This example again raises the question of why EPA's proposed approach ends up treating similar units so differently. We again point out that such anomalies would be eliminated simply by using measured heat input as a basis for issuing allowances, rather than trying to use IPM predictions about future emissions at the unit level. [EPA-HQ-OAR-2009-0491-2843.1, p.10]
IV. Regardless of how IPM is used, it contains a number of inaccuracies and incorrect assumptions that must be corrected before it can be used for decision-making
A. IPM Does Not Properly Incorporate the HAA
As noted above, there are a number of anomalies in the way that IPM predicts future emission rates from EGUs located in Maryland  -  anomalies that simply do not square with the investments that companies have made to meet the HAA. Based on conversations between Mirant and EPA staff, Mirant believes that the HAA requirements are not accurately incorporated as constraints in IPM. In particular it is important to understand the system-wide compliance approach adopted by the State Legislature. See COMAR <IP_ADDRESS>(e) (System-Wide Compliance Determinations) and <IP_ADDRESS>(B)(3) (defining system as 2 or more EGUs owned or operated by the same person). Each of the three major companies essentially has a hard cap that covers all the units that it owns in the state. Before making any decisions based on IPM, EPA needs to ensure that the model properly deals with the HAA. [EPA-HQ-OAR-2009-0491-2843.1, pp.10-11]
B. IPM Does Not Accurately Predict the Operation of Higher Cost Peaking Units
IPM contains certain simplifying assumptions that make it unsuitable for projecting how individual units are operated (and will continue to be operated) in the real world. For example, it is our understanding that, if a 1000 MW unit has an average capacity factor of 85 percent, the model assumes that this unit is actually an 850 MW unit that is available all the time. If this were true, then power prices would be much more predictable and stable than they actually are in the real world. The following table, based on day ahead price data from 2007 through September 2010, shows the extent and frequency of price spikes in the three zones where Mirant operates plants covered by the Transport Rule: PEPCO, Hudson Valley, and Southeast Massachusetts.
[This table can be found on page 11 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.11]
Thus, in the PEPCO Zone, 13 percent of the time, hourly prices are more than 50 percent higher than the monthly average, and 2 percent of the time they are more than 100 percent higher. This is enormously important in the real world. IPM projects that a number of higher cost plants will not run under the Transport Rule and, as a result, they receive no allowances. In fact, however, they play an important role in individual markets. [EPA-HQ-OAR-2009-0491-2843.1, p.11]
Although IPM believes these relatively higher cost plants to be uneconomic, the market finds them to be quite valuable  -  as evidenced by the capacity payments that are made to ensure that these units are available when they are needed. For example, IPM predicts that oil-fired plants will not operate, but the following tables show otherwise. [EPA-HQ-OAR-2009-0491-2843.1, pp.11-12]
The first table shows that substantial amount of oil burn at Mirant's dual-fuel units. The second table shows that the units are not just summer peaking but run substantially through the year . The third table contains Confidential Business Information (CBI) and is not included in these public comments. In accordance with EPA regulations, it has been submitted separately. It shows the aggregate volume of fuel burned at each unit to provide an appreciation of the scale of operations.
[The first two tables can be found on page 12 of this comment. [As explained on page 12 of this comment, the third table includes CBI and has been submitted separately, in accordance with EPA regulations.] [EPA-HQ-OAR-2009-0491-2843.1, p.12]
Not surprisingly, it appears that IPM is particularly ill-suited for modeling dual fuel units, i.e., units capable of burning either natural gas or oil. Of the 493 dual fuel units in the NEEDS database, IPM predict that, in the 2014 limited trading control strategy, only 34 units would burn oil as the primary fuel. EPA proposes to allocate SO2 allowances to only 8 of these 34 units. This result ignores the reality that many dual-fuel units do regularly burn oil for some part of the year, due to a variety of real-world factors, including natural gas supply limitations, price factors, or facility-specific constraints. The mere fact that the IPM may project that it will be more economical to run these units on natural gas than on oil does not mean that the real-world factors that lead to combustion of oil at these units simply disappear. These factors include the mismatch between electricity and gas markets (as gas markets close at 6 pm and do not open again until 10am); gas pipeline constraints (gas demand for heating is high on very cold days); many if not most units are on "interruptible" gas; requirements to take gas ratably in equal 24 hour installments when electricity demand has a different profile; natural disasters that affect the amount of gas available. [EPA-HQ-OAR-2009-0491-2843.1, pp.12-13]
Finally, IPM (and thus the proposed allocation scheme) simply does not address local circumstances in many areas, including areas with specific load pockets and transmission constraints. For example although recent transmission upgrades allow more distant plants to serve Cape Cod, Mirant's Canal plant is the only generation on Cape Cod. IPM views this plant as uneconomic and predicts that it will no longer operate, but again, this is contrary to the facts on the ground. The Canal plant serves and important purpose in this area and should receive allowances based on historic heat input rather than predictions from an overly simplified model that was not designed to deal with individual units. [EPA-HQ-OAR-2009-0491-2843.1, p.13]
C. There are Obvious Factual Errors Related to Mirant Units
It appears that EPA has made a mistake in how it treated the scrubbers at Morgantown Units 1 and 2 and Dickerson Units 1, 2, and 3. The Agency apparently assumed that they would be built in the future in response to the Transport Rule. In fact, they were designed and built in response to the HAA, and came on line in December 2009. We have been informed by EPA staff that, in the parsed file, the Morgantown and Dickerson scrubbers should have been listed in column O for existing equipment. [EPA-HQ-OAR-2009-0491-2843.1, p.13]
To ensure that EPA has correct information about Mirant's scrubbed units, Mirant provides the following information about the actual SO2 rates that have been achieved year to date since the scrubbers were installed in response to the Maryland HAA:
[The information can be found on pages 13-14 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.13]
It also appears that there is an input problem with all EGUs in Maryland. The ozone-season NOx emission rates for all Maryland units appear to be too high by approximately a factor of 10. It appears that there may have been an effort to correct this problem by reducing the heat input for each unit by approximately a factor of 10. It is unclear, however, whether these errors fully cancel each other out or whether they are somehow propagated throughout the model. It would be preferable to use the correct data for ozone-season NOx emissions rates and heat input. [EPA-HQ-OAR-2009-0491-2843.1, p.14]
National Mining Association (NMA)
NMA understands that utility industry commenters will provide significant information showing that EPA has made factual errors in the modeling inputs that were used to demonstrate that the phase one emission reduction reductions could be achieved by the beginning of 2012. For instance, NMA understands that this information will show that EPA has overstated the number of scrubbers that are under construction and will be operational by 2012. If EPA's information is wrong, then the only way the 2012 budgets can be met are by closing units or ramping down production, a result that would fundamentally change the cost-effectiveness of the rule. [EPA-HQ-OAR-2009-0491-2868.1,p.16]
If Shale Gas Claims Prove to be Too Optimistic, High Natural Gas Prices and Price Volatility Will Return, Hurting All Consumers [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.6]
Natural gas historically has been considerably more expensive than coal. Increased natural gas generation has led to higher electric rates across the nation, from 6.81 cents/kWh in 2000 to 10.02 cents/kWh in 2009. For all consumers, natural gas for power generation will remain more expensive than coal-based generation. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.6]
Electricity price volatility adversely impacts consumers and manufacturing alike. Further, a wide variety of manufacturing firms utilize natural gas in the production process -- often as an essential feedstock. The impact of natural gas price volatility on these companies is far-reaching. According to Edward Stones, in testimony for Dow Chemical Co. before the U.S. Senate in 2009, '[s]ince 1997, there have been five natural gas price spikes.... These price spikes have significantly contributed to the U.S. manufacturing sector losing over 3.7 million jobs. In a 'peer-reviewed scientific paper in Environmental Science and Technology, Professor Jay Apt and Adam Newcomer at Carnegie Mellon University concluded that, with the cancellation of new coal generation, 'the amount of time that natural gas generators set the market price of electricity would increase substantially, and other industries that use natural gas may be priced out of the market.' [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.7]
Natural gas prices and increased volatility of those prices over the past decade have severely affected families. In 2000, for example, residential gas prices started at $6.37/mcf but escalated to $13.74 in 2004. They then jumped to $20.24 in 2008 but dropped to $11.25 by the end of 2009. Upwards of 60 percent of the homes in the United States are heated with natural gas. Many of these homes are concentrated in the Midwest and Mid-Atlantic states. During the winter their dependence on natural gas is virtually total since most lack alternative sources of heating. And, of course, during the summer many states are highly dependent upon gas-fired generation to meet peaking cooling demand. In total, 33 states are vulnerable to natural gas price volatility because of heavy reliance on gas for heating and/or electricity generation. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.7]
Nebraska Public Power District
Furthermore, because of serious errors in EPA's emissions inventory for Nebraska as outlined below and major deficiencies with the "significant contribution" procedures, EPA must redo the modeling analysis that was used for identifying Nebraska as a State that is subject to the annual SO2 and NOx reduction requirements under the TR. In so doing, EPA also should allow additional time for NPPD and other interested parties in Nebraska to provide further technical input on the effects of these errors, as well as all measures that EPA may take to correct these fundamental flaws with the modeling analysis that it has used for identifying those states that are included in the Transport Rule. [EPA-HQ-OAR-2009-0491-2711.1, p.1]
Conclusion. While EPA proposed 2012 EGU emission budgets in Nebraska approximately equal to 2009 emissions, it modeled greatly inflated base-case 2012 SO2 emissions for Nebraska. It is clear that these base case projections do not correspond to historic operation of the coal-fired EGU units and are not representative of future SO2 performance of these units. This conclusion is particularly underscored given that the Nebraska EGU units are currently not subject to CAIR and EPA has not identified any changed circumstances that could justify this steep increase in SO2 emissions under the 2012 base case. [EPA-HQ-OAR-2009-0491-2711.1, p.6]
5) Nebraska EGU NOx Emissions Inventory. Similar to the problem outlined in Item 4 [page 3 of this comment], NOx emissions from EGUs are overstated. The two new coal-fired units described above are very well controlled, and with low-NOx burner projects being required under the Regional Haze program, total EGU emissions of NOx are likely to decrease between 2005 and 2014, rather than increase slightly as forecast by EPA. [EPA-HQ-OAR-2009-0491-2711.1, p.6]
[For additional comments pertaining to Nebraska EGU NOx Emissions Inventory, see p.6 of this comment]
6) Importance of Fixing Flaws in Nebraska Emissions Inventory. Given the several major emissions inventory problems identified in Items 2-5 above [pages 1-6 of this comment], EPA should therefore correct its modeling analysis for Nebraska based on accurate base case projections for EGUs and other source categories. Failure to do will result in EPA including Nebraska in the TR based on major flaws in the emissions inventory data. Emissions inventory problems of lesser magnitude in Minnesota, for the prior CAIR rule modeling analysis, resulted in the issue being remanded to EPA for further study (D.C. Circuit of the U.S. Court of Appeals, in North Carolina v. EPA, decided July 11, 2008). [EPA-HQ-OAR-2009-0491-2711.1, pp.6-7]
Nelson Industrial Steam Company (NISCO)
EPA's approach for projected emissions inventories eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR: reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-2813.1 , p.6]
NISCO supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). NISCO urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in NISCO's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.2]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, NISCO believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' under the 'good neighbor' provisions of the Clean Air Act,_42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. NISCO urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.4]
New York State Department of Environmental Conservation
Future year 2012 and 2014 base case EGU emissions used for the air quality modeling runs that predicted ozone and PM2.5 were obtained through the use the IPM model. This model is a proprietary model that was applied to analyze its EGU strategies which was fed with proprietary control cost databases. The use of proprietary databases and models is inappropriate. To be able to assess the manner in which the model was applied, the public should be able to review all of the algorithms and all of the data that EPA used in the IPM model and not just a summary. [EPA-HQ-OAR-2009-0491-2730.1, p.9]
Northern Indiana Public Service Company (NIPSCO)
NIPSCO, as well as numerous other utility companies that would be subject to the proposed rule, have identified a number of incorrect assumptions and unrealistic results in EPA's modeling assumptions and results. Specifically, for NIPSCO units, the following EPA assumptions are impractical. [EPA-HQ-OAR-2009-0491-2747.1 p.4]
EPA needs to reexamine the set of IPM assumptions for NOx emission control reductions, if currently installed NOx control equipment is used to determine emission allowance allocations. Use of an unrealistically high level of emission control results in an allocation of allowances that are correspondingly insufficient for a controlled source and leads to the need to supplement emission allowance holdings on an emission unit equipped with an SCR. The table below illustrates the problems mentioned above. Michigan City Unit 12 and R. M. Schahfer Unit 14 are examples of boilers controlled by SCR which have not demonstrated the ability to achieve the emission rates assumed in the IPM over an extended period of time. Both units are cyclone fired boilers that have high uncontrolled NOx baseline rates that are not properly reflected in the presumed rates in IPM. NIPSCO believes that the assumption within IPM that all SCRs achieve a 90% reduction on a long term basis with a floor of 0.06 lb/mmBtu is not appropriate for high NOx baseline units such as cyclone-fired boilers. [EPA-HQ-OAR-2009-0491-2747.1 p.4]
[[Data Table Here]]
Additionally, there appears to be an error in the application of flue gas desulfurization ('FGD') at the R. M. Schahfer Station Units 17 and 18. These NIPSCO generating units have had FGD installed and removing sulfur dioxide ('S02') at a rate just above 90% since the units began operating in the 1980's. Yet, in spite of operating FGD as shown in Table 2 below, Units 17 and 18 are further subject to additional reductions significantly beyond what is presently capable from these FGD systems. Within the last year NIPSCO upgraded both Units 17 and 18 FGD systems to improve the S02 removal capability; however, the units are not capable of achieving reductions assumed in EPA's emission allocation methodology. NIPSCO requests a correction of this error. [EPA-HQ-OAR-2009-0491-2747.1 p.5]
[[Data Table Here]]
NIPSCO believes inaccuracies and incorrect assumptions for our units individually, and in combination with similar inaccuracies and projections across the domain of states included in the Transport Rule, lead to incorrect characterization of emissions that affect the air quality impacts and subsequent conclusions regarding the necessity and scope of controls. [EPA-HQ-OAR-2009-0491-2747.1 p.5]
If EPA proceeds with its proposed FIP approach,2 NIPSCO proposes that EPA consider basing the unit allocations on a unit's proportion of its state's historic heat input (i.e., million British thermal units, mmBtu). The historic heat input should be based on the maximum annual heat input for units during a baseline period that should include a period of five years and at a minimum the three year period covering calendar years 2007 through 2009. The EPA should consider a longer baseline period because of the unusual weather conditions in 2008 and 2009 and the economic downturn that occurred at the same time, in order to ensure that the period provides for representative production levels. We recommend using the annual maximum on a unit specific basis of the reported data during the baseline period rather than the average of the baseline period in order to ensure an unusual year does not dramatically alter the allocation (e.g., an extended boiler outage).  [EPA-HQ-OAR-2009-0491-2747.1 p.5]
Northern Star Generation LLC
comments on the FIP, both as a company and as part of the trade association ARIPPA. In our comments we have strongly objected to EPA's use of modeled future unit dispatch as the basis for allowance allocations under the Transport Rule. It is our recommendation that EPA return to the historic approach of using historic heat input as the most equitable basis for allowance allocation under this cap and trade program. However, in the event that EPA intends to utilize modeled unit dispatch projections and projected emissions as the basis for allowance allocation, we feel that it is extremely important that EPA use accurate data on plant availability, heat rate, and fuel cost in the model. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.1]
NRG Energy
Natural gas prices based on EIA's Annual Energy Outlook (AEO) NRG is concerned that allocations, through the projected heat input, are sensitive to natural gas price assumptions. Natural gas price assumptions can affect the IPM results on a state-by-state basis. For example, the total heat input (tBTU) by state varies from 1% to 12% when comparing the TR base case V.4.10 2012 run to the TR Base AEO Gas V.4.10 2012 run. For determining the state-level budgets and unit-level allocations, NRG recommends EPA use EIA's Annual Energy Outlook natural gas resource assumptions because the AEO has a set of assumptions that is widely used and trusted by the energy industry. [EPA-HQ-OAR-2009-0491-2749.1, pp. 3-4; see p. 4 for related table.]
Oglethorpe Power
It is unclear as to why EPA failed to use 2008 heat input date for SO2 as it did for NOx. This is especially so, given that 2009 was, as EPA admits, an 'unusually low year' for utility operations. It seems apparent that anyone year, especially one where operations were unusually depressed (due to a rather severe recession) should not serve as a time period upon which to base historical operations for use in allocation calculations. Here, allocations of S02 and NOx allowances should be based on a similar if not identical baseline, unless EPA can justify disparate treatment of the two pollutants. 2009 is not a representative year, given the recession and corresponding depressed (and not wholly realistic) demand for electricity experienced in virtually all the states in the Transport Region. Whatever the reason EPA used 2008 instead of 2009 data for only one pollutant, EPA failed to make a similar adjustment for unit-reported SO2 emissions. EPA does not provide any explanation for this differential treatment of the baselines for the two pollutants. EPA should clarify and explain more fully why it chose not to use 2008 (which is certainly a more representative year for utility operations instead of 2009) data for SO2 (as it did for NOx). [EPA-HQ-OAR-2009-0491-2732.1, p.4]
III. Unit Allocations
Several of the unit annual NOx allocations for units owned and/or operated by Oglethorpe Power determined by EPA appear to be in error. The table below summarizes these errors, caused by missing data, broken out by unit. [EPA-HQ-OAR-2009-0491-2732.1, p.5]
[The table can be found on pages 5 and 6 of this comment.]
The 'X' entries in the above table indicate missing data (specifically with regard to 2008 annual heat input and NO, emissions for the four most recent quarters). The missing heat input and/or emissions data prevents the assigning of NOx annual allowances to the units listed above. Note that these units do receive seasonal allocations under the Transport Rule. Annual allocations should be at least equal to the seasonal allocations in all cases. EPA should revisit its annual NOx allocations for these units and true up its determinations as needed. Based upon Oglethorpe Power's analysis, Oglethorpe Power should receive 80 additional NOx annual allowances corresponding to the units listed above. [EPA-HQ-OAR-2009-0491-2732.1, p.6]
[For additional comments pertaining to 2014 SO2 allocations, see page 6 of this comment]
It is unreasonable and inequitable to base allocations on anyone year's (or four quarters') worth of heat input, given the vagaries of any EGU's operating performance in a given year, especially a year where a scheduled outage for extensive maintenance falls or a forced outage of any appreciable length of time occurs. The problem is exacerbated where EPA picks a year of severe depressed economic conditions, here the last part of 2008 and the remainder of 2009, where generation was unusually depressed due largely to the national recession. The recession was particularly hard on Georgia, where all of the Corporation's generation assets are located. Unemployment has been higher in Georgia than the rest of the southern U.S. (10.0% versus 9.3% in August of 2009) and remains higher today (10% versus 9.2% in August 2010), while 2009 per capita income was for 2009 some 6% lower in Georgia as compared to the southeast as a whole ($33,980 versus $36,033). 7 [EPA-HQ-OAR-2009-0491-2732.1, p.7]
A plethora of CWA-related rulemakings and programs, like CAIR, the Clean Air Mercury Rule ('CAMR'), 8 regional haze, new source review, and ever-tightening NAAQS have resulted in lengthy scheduled outages required for installation of controls needed for compliance. A more equitable and reasonable approach in the Transport Rule would be to use a number of years as the historical basis for determining the allowance allocation from the state budgets to covered units, to account for the operational variations that could negatively skew allocations to the individual units by using a timeframe of only one year (or four quarters). This is especially true where the Agency is adopting permanent allocation programs of the type contemplated in this rulemaking. [EPA-HQ-OAR-2009-0491-2732.1, p.7]
It is also unreasonable and arbitrary to base unit allocations on EPA computer model projections of both future individual unit utilization and emission reduction capability, especially where such model fails to consider all of the variables (many of which are today unknown) that will determine utilization and control in upcoming years. Regardless of the purported sophistication of EPA's IPM, it does not and cannot accurately forecast how each and every fossil fuel-fired unit in the Transport Rule's 32 state trading areas will be utilized, or what the future costs and results will be in meeting the emission reduction obligations dictated by the model. The model cannot account for the myriad of future business decisions Oglethorpe Power and its 39 member systems will make that will affect the source and mix of generation assets to meet its ever increasing demand, the details of numerous power supply agreements (many of which have not yet even been created), upcoming negotiations and resulting agreements for transportation and ever-changing variable costs (like fuel), all of which will directly affect the manner and costs of supplying wholesale power to the 39 member systems Oglethorpe Power is obligated to serve. While EPA may think that trading will smooth out any uneven playing field created by erroneous, inaccurate, incomplete or incorrect assumptions that are critical inputs to the IPM, it is fantasy to believe that trading (which will be severely limited at best in any scenario proposed by the Agency) will be able to provide any meaningful relief for any substantial errors made in the unit allocations. This is especially true if EPA makes the allocations permanent. [EPA-HQ-OAR-2009-0491-2732.1, pp.7-8]
Here, if EPA bases any of its allocations on 2009 data, the derived allocations will prejudice Oglethorpe's units at Plant Scherer, both of which had scheduled outages of substantial lengths in 2009 to install controls triggered by state rulemakings to implement a CAMR SIP. Other Oglethorpe Power units that did not run (because they were not needed) during the recession last year (in this case during the 2009 ozone season) are also unfairly hurt if 2009 is used as the sole operational baseline tor determining unit allocations. [EPA-HQ-OAR-2009-0491-2732.1, p.9]

7. U. S. Bureau of Labor Statistics, Economic News Release - Regional and State Employment and Unemployment - August 2010 (September 21, 2010) and U.S. Bureau of Economic Analysis, Per Capita Personal Income (SAI-3) from the Regional Economic Information System (September 2010). [EPA-HQ-OAR-2009-0491-2732.1, p.7]
8.  Even though CAMR was vacated by the U.S. Court of Appeals for the District of Columbia Circuit, SIPs adopted as part of state rulemakings to submit an approvable CAMR SIP could result in enforceable State obligations independent of the CAMR, which continue unabated despite the CAMR vacatur. Exactly that situation has occurred in Georgia, which adopted specific control requirements (flue gas desulfurization scrubbers, SCRs and, in some case, baghouses, all on prescribed schedules), in part to control emissions of mercury from coal-fired EGUs. [EPA-HQ-OAR-2009-0491-2732.1, p.7]
Ohio Utility Group (OUG)
The Proposed Transport Rule is Based Upon Inaccurate Data and Flawed Methodology [EPA-HQ-OAR-2009-0491-2679.1, p.4]
EPA has proposed to find that emissions of S02 and NOx contribute significantly to non attainment or interfere with maintenance in one or more downwind states with respect to at least one of the following air quality standards: 1) the annual average PM2.5 NAAQS; 2) the 24-hour average PM2.5 NAAQS; and 3) the ozone NAAQS. The Utilities object to the data and methodology EPA used to determine a state's 'significant contribution' and to finalize state budgets. [EPA-HQ-OAR-2009-0491-2679.1, p.4]
In an attempt to correct the deficiencies of previous rules enacted pursuant to section 11O(a)(2(D)(i)(I)8, EPA proposed a 'state specific methodology' to identify specific reductions that individual states must make to eliminate their significant contributions to nonattainment in downwind states.9 EPA's methodology will require an initial set of emissions reductions in 2012, followed by a second set in 2014. To facilitate implementation, EPA developed state emissions budgets derived from an analysis of cost thresholds and state-specific emissions data. EPA determined that a state's emissions budget 'is the quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution, before accounting for the inherent variability in power system operations.' [EPA-HQ-OAR-2009-0491-2679.1, p.4]
The Utilities object to the imposition of these budgets on several grounds. Most notably, as the individual member Utilities are concerned, EPA's proposed state budgets were based on incorrect assumptions and inaccurate data. The Utilities assert that the modeling data EPA used is out of date and inaccurately assumes the existence of equipment that has not been installed and, thus, capabilities that have not been reached. [EPA-HQ-OAR-2009-0491-2679.1, p.4]
If EPA insists on pursuing unit-by-unit controls, the data must be accurate. Otherwise complying with allocations becomes untenable. Inaccurate assumptions were made with respect to members of the OUG. For example, AEP Cardinal Unit 3 and OVEC's Kyger Creek Units 1-5 were assumed to have wet scrubbers that, due to construction delays, will not be operable by the proposed January 1,2012 deadline. OVEC is still working on resolving the issues and does not expect Kyger Creek to be fully retrofitted until mid-2012. OVEC also highlights that all of its units are equipped with wet-bottom boilers. EPA previously acknowledged that units with wet-bottom boilers are inherently higher NOx emitters than dry-bottom boilers. Accordingly, wet-bottom boilers were provided with almost twice the NOx allowances. I I Yet, EPA inexplicably ignores those differences in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2679.1, p.4]
Faulty assumptions made about DP&L's Stuart and Killen stations have detrimental effects. CAIR provided Killen with 3,326 annual NOx allowances in 2009. The Transport Rule provides only 1,127 annual NOx allowances, a 66% reduction. Similarly, CAIR provided Stuart with 11,190 NOx allowances per year in 2009, whereas the proposed rule provides only 4,512. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
The Utilities' objection to the modeling data should not come as a surprise as EPA has already begun to reevaluate the data it applied in the proposed rule. On September 1, 2010, EPA issued a Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone ('NODA,,).12 The NODA supplemented the proposed Transport Rule with more recent emissions inventory data, new cost information, and an updated Integrated Planning Model. The information in the NODA has a direct effect on determining a state's 'significant contributions,' state emissions budgets, and unit allocations. While EPA has not yet re-calculated state budgets, the fact that EPA took the time to incorporate a substantial amount of data into the record is an indication that EPA appreciates the importance of applying accurate data. The Utilities maintain that if current budgets are applied without being reevaluated, states will be forced to accept inadequate budgets, ultimately resulting in a substantial number of units failing to comply with budget allocations. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
The Expectations Under The Proposed Rule Are Unreasonable [EPA-HQ-OAR-2009-0491-2679.1, p.5]
EPA's actions are unreasonable. The Utilities' objections thus far have expressed concern about the required emissions reductions in terms of amount of actual reductions. The Utilities conclude by expressing concern with respect to the timing and economic requirements under the proposed rule. In light of EPA's reliance on the faulty assumptions and inaccurate data mentioned above, the proposed rule requires emissions reductions that are not feasible and will ultimately result in unforeseen consequences. In this final section, the Utilities provide real world examples supporting the notion that EPA's expectations are entirely unrealistic. Finally, the Utilities will demonstrate that such stringent emissions reductions are unnecessary. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
The Utilities anticipate major complications if facilities are forced to switch coal. Based on the recently released IPM runs in conjunction with the NODA, emissions rates for AEP's Muskingum River units 1-4 were as low as 1.42 lb-S02/mmBtu based on the modeled emissions and heat input. In previous runs used to support the Transport Rule, the emissions rates were a slow as 1.011b- S02/mmBtu. As these are uncontrolled units, the emissions rate is largely indicative of the sulfur content of the underlying fuel. However, low sulfur eastern fuel(s) are not compatible with these wet-bottom boilers due to ash fusion and ESP limitations. These units are currently limited to coal(s) with an S02 content of 4.0 lb/mmBtu or above. Similarly, OVEC's Kyger Creek scrubbers were designed to bum higher sulfur coal. [EPA-HQ-OAR-2009-0491-2679.1, p.6]
The assumed coal switch also has significant economic repercussions. EPA's modeling does not take into account long-term coal purchase contract obligations and the ability to quickly ramp production up and down. The IPM model allowed full switching to low sulfur coal in 2012, but in the real world this could not occur. If the final model would ultimately push DP&L to switch coals, DP&L would be forced to shift sourcing millions of tons of coal per year at a cost near $50 Million per year. OVEC currently has two contracts for local Ohio coal for use at Kyger Creek: one set to expire at the end of 2012 and the other at the end of 2017. Like DP&L, OVEC may be forced to purchase lower sulfur coal to comply with the strict limitations, possibly causing OVEC to default on its long-term local coal contracts. [EPA-HQ-OAR-2009-0491-2679.1, pp.6-7]
B. No data base or modeling platform can be accurate without assuming the control technology installed, and air quality improvements realized, under CAIR
If the information in the NODA contains 'updated' versions of the NEEDS database and IPM platform, why do these new versions still fail to consider CAIR? The Utilities commented on the appropriateness and necessity of including the control technologies and air quality improvements resulting from the CAIR program.  As such, the Utilities will not go into great length repeating what has already been said. However, the inclusion of CAIR is fundamental to the final Transport Rule and cannot go unmentioned in these comments. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
Twice now, EPA has acknowledged the advancements in air quality made in recent years as a result of CAIR. In the proposed Transport Rule, EPA stated that 'a great deal of the improvement in PM2.5 and 24-hour concentrations in the eastern U.S. can be attributed to EGU reductions achieved due to the CAIR.'  From this, EPA recognized that the final Transport Rule must use more recent data to account for these improvements. 'EPA intends to update the NOx rates for fossil-fuel fired units in the final rule to reflect the more recent 2009 data ... The updated NOx rates will more accurately portray the unit level control installations that have occurred at power plants during the past several years.,, The significance of EPA's intentions is not clear. Will these updated NOx rates require assuming CAIR, at least in part? If CAIR is being assumed for one aspect of the Transport Rule, logically, CAIR must be assumed for the entire rule. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
One thing is certain - no database or modeling platform is sufficiently 'updated' unless it assumes CAIR. Modeling analysis performed by Midwest Ozone Group ('MOG') demonstrates that Ohio NOx and S02 caps similar to the caps developed under CAIR, accounting for the control measures installed to comply with CAIR, are adequate to eliminate Ohio's 'significant contribution' to downwind non attainment in almost all areas by 2014 - before the NAAQS attainment deadlines. MOG's modeling presents an entirely different picture than that performed by EPA. EPA's rationale for excluding CAIR in the proposed Transport Rule is unfounded. Therefore, the Utilities respectfully request that EPA assume all air quality improvements and emissions controls under the CAIR program. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
OVEC owns and operates two coal-fired electric generating plants (the OVEC Units) located on the Ohio River. OVEC's Kyger Creek plant is located in Gallia County, Ohio, and the Clifty Creek plant is located in Jefferson County, Indiana. OVEC is submitting these comments to correct several factual mistakes EPA made when inputting data for the OVEC Units, most significantly EPA's assertion that all eleven OVEC Units will be equipped with Flue Gas Desulfurization (FGD) before January 1,2012. OVEC also demonstrates why the Proposed Transport Rule's overly aggressive and unjustified emission reduction targets and timetables are unreasonable and not feasible for OVEC. [EPA-HQ-OAR-2009-0491-2803.1, pp.1-2]
Incorrect Factual Inputs EPA's Modeling [EPA-HQ-OAR-2009-0491-2803.1, p.3]
EPA has made several factual errors about the OVEC Units that must be corrected before finalizing any rule regarding electric generating unit (EGU) emissions allocations. Briefly, those mistakes are: [EPA-HQ-OAR-2009-0491-2803.1, p.3]
Clifty Creek will not be fully retrofitted with FGD as of January 1, 2012 [EPA-HQ-OAR-2009-0491-2803.1, p.3]
Kyger Creek will not be fully retrofitted with FGD as of January 1,2012 [EPA-HQ-OAR-2009-0491-2803.1, p.3]
All of the OVEC Units are wet-bottom boilers, and cannot meet the proposed NOx targets even with EPA's assumed NOx controls [EPA-HQ-OAR-2009-0491-2803.1, p.3]
The NOx Emission Targets for OVEC are Unreasonable and Unachievable. [EPA-HQ-OAR-2009-0491-2803.1, p.5]
OVEC first addresses EPA's NOx allocations for the eleven OVEC Units. EPA has clearly stated on numerous occasions that the 2012 emission reduction requirements in the Proposed Transport Rule are based on emission control equipment that is currently or scheduled to be in place by January 1, 2012. In fact, on the surface, it appears that EPA correctly assumes that the current NOx controls at the OVEC Units - ten SCRs and eleven units equipped with OFA - will be in place in 2012. However, the emission targets that EPA incorrectly assumes can be met with those controls are well below anything reasonably attainable. [EPA-HQ-OAR-2009-0491-2803.1, p.5]
Never once, taking the last five years of historical operation into account, has OVEC ever achieved the NOx emission levels required of it by 2012 under the Proposed Transport Rule. The table below shows OVEC's ozone season and annual NOx emissions historically for each plant [EPA-HQ-OAR-2009-0491-2803.1, p.5; see pp.5-6 for Table 2 entitled, Historical NOx Emissions at OVEC Units]
Under EPA's Proposed Transport Rule, OVEC would be required to achieve the same NOx emissions in 2012 as 2014. However, based on actual, historical operating data, it is impossible for the OVEC Units to comply either with the seasonal or annual NOx emissions limitations EPA has proposed: [EPA-HQ-OAR-2009-0491-2803.1, p.6; see p.6 for Table 3 entitled, Comparing estimated ozone season NOx emissions at historic heat Inputs to Proposed Transport Rule allocations; see pp.6-7 for Table 4 entitled, Comparing estimated annual NOx emissions at historic heat inputs to Proposed Transport Rule allocations]
The SO2 Emission Targets for the OVEC Units are Unreasonable [EPA-HQ-OAR-2009-0491-2803.1, p.7]
OVEC also takes issue with the overly aggressive and arbitrary SO2 emissions reductions proposed for the Kyger Creek and Clifty Creek plants. Again, EPA has clearly stated that the 2012 emission reduction requirements in the proposed rule are based on emission control equipment that is currently or scheduled to be in place by January 1, 2012. The first problem, as discussed above, is that due to the extreme economic recession - the deepest and longest since World War II that has hit the Midwest particularly hard - and serious design problems with the FGDs, neither plant will be fully equipped with FGD by January 1, 2012. The vacatur and then remand of CAIR has also impacted the economics of FGD retrofit schedules. The very basic factual inputs that EPA used are incorrect. [EPA-HQ-OAR-2009-0491-2803.1, p.7]
The problems with the SO2 emission reduction targets for OVEC's units are not limited to the incorrect factual inputs for retrofit completion dates. OVEC has analyzed its historical operating data, the guarantees in its FGD vendor contracts, its coal contracts, and industry experience with the type of FGD it is installing to assess the feasibility of complying with the proposed SO2 emission caps. Attempted SO2 compliance with the Proposed Transport Rule in its current form is unreasonable and infeasible. [EPA-HQ-OAR-2009-0491-2803.1, p.7]
For example, if Kyger Creek uses the locally based Ohio coal with the sulfur content the scrubbers are designed for, the scrubbers would have to operate at or above a 98% removal efficiency year-round to even come close to achieving the SO2 emission reductions proposed by EPA in 2012. A change in removal efficiency of less than one percent would cause the units to exceed the proposed cap. There is very little industry operating experience with Chiyoda Jet Bubbling Reactors, and none that suggest they could achieve this level of performance with no equipment or learning curve problems. The scrubbers will not be started up and optimized until after the 2012 initial reduction date, and they cannot reasonably be expected to constantly achieve maximum peak operational performance from the first day the scrubbers are turned on. [EPA-HQ-OAR-2009-0491-2803.1, pp.7-8]
The 2014 SO2 emissions caps are even more stringent. Assuming that all of the scrubbers will be operating at peak performance by 2014 (which is by no means certain), OVEC would have to operate the scrubbers at a removal efficiency that may not even be achievable, and do so without a single equipment problem year-round. [EPA-HQ-OAR-2009-0491-2803.1, p.8]
Factual Errors about the OVEC Units [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
EPA's NEEDS database does not reflect the factual circumstances for the two coal-fired electric generating plants that OVEC owns and operates (the OVEC Units), and the outputs published by EPA are internally inconsistent, and inconsistent with OVEC's planned retrofits. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
Kyger Creek [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
First, EPA failed to correct the NEEDS database to reflect that Kyger Creek does not have Flue Gas Desulfurization (FGD or scrubber), nor will it before mid-2012 at the earliest. The NEEDS database still incorrectly lists a scrubber in place as of 2010. OVEC has already supplied information demonstrating that the scrubber at Kyger Creek is currently not anticipated to be fully operational until mid-2012, absent unforeseen disruptions. The fact that EPA issued 'updated' data inputs before it ever received comments on its first set of incorrect facts contributes to the confusion and inability to fully assess the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
Second, EPA's modeling outputs are inconsistent with their inputs and with themselves. Despite incorrectly assuming a scrubber is in place at Kyger Creek in 2010, EPA's published model outputs show the scrubber disappearing in 2012. The emission rates and heat rate information in the parsed files state that Kyger Creek will be burning 100% bituminous coal with no scrubber in 2012. Further confusing the matter, the scrubbers 'reappear' in the 2014 parsed file, albeit with no indication of the projected removal efficiency. As OVEC has already stated in its PTR comments: Kyger Creek burns a blend of bituminous and subbituminous (PRB) coal, and will continue to do so until it is fully retrofitted with FGD. Therefore none of the data EPA has published about Kyger Creek regarding SO2 is correct. OVEC cannot resolve EPA's inconsistencies, and cannot provide meaningful further comment until EPA resolves its own inconsistencies and corrects its factual mistakes. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
EPA also makes mistakes at Kyger Creek about NOx emission rates. EPA once again lists 'baseline' rates below that which Kyger Creek has been able to achieve based on historical, actual operation. (See PTR Comments). [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
Finally, as we discuss below, EPA has not updated any of its SO2 or NOx allocations, so OVEC has no way of knowing how these factual errors will eventually affect the centrally relevant unit allocations, and whether EPA will continue to set overly restrictive and unreasonable targets for the OVEC Units. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
Clifty Creek [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
At Clifty Creek, EPA correctly changed the factual inputs to reflect that Clifty Creek does not currently have any installed FGD. However, it mistakenly assumed that Clifty Creek is currently burning 100% bituminous coal. As explained in its PTR Comments, OVEC spent almost $80 million in connection with switching to a blend of bituminous and subbituminous coal at Clifty Creek. The NEEDS database must be updated to reflect accurate facts. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
Another serious error in EPA's 2014 parsed file is the assumption that Clifty Creek will be burning 100% subbituminous coal. This is not only at odds with the fact that all units at Clifty Creek are currently scheduled to be retrofitted with FGD by mid-2013, but is a completely unreasonable assumption for the Clifty Creek units. As stated in its PTR Comments, Clifty Creek can burn up to 75% subbituminous coal. Wet-bottom boilers which all of the OVEC Units are - experience numerous operating problems even at a 75% blend of subbituminous coal. Even if it were possible for Clifty Creek to burn 100% subbituminous coal - an assumption OVEC believes is not feasible - burning 100% subbituminous coal would result in a significant derate of the units. 1 EPA has either ignored this or failed to consider it by not changing the assumed gross capacity - 217 MW/unit - an impossible rating if the units could burn 100% subbituminous coal. EPA also fails to explain whether it considered the inevitable operational difficulties resulting from burning high ratios of subbituminous coal in its reliability analysis, because a wet bottom boiler burning 100% subbituminous coal would likely suffer a large loss of reliability. EPA has not considered the enormous costs of capacity derating and reduced availability associated with its 100% subbituminous assumption for Clifty Creek. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
Apart from the flawed assumption that Clifty Creek could burn 100% subbituminous coal EPA failed to account for the fact that OVEC is constructing a scrubber for all units at Clifty Creek. As indicated in its PTR Comments, the current schedule for completion of the Clifty Creek scrubbers is mid-2013. There is no basis that OVEC can see why EPA assumed away Clifty Creek's scrubber in its entirety - particularly when the scrubber is already approximately 35% complete. This illogical and uneconomical 'result' from the modeling demonstrates the need for EPA to take the necessary time to fully consider its inputs and the reasonability of its outputs before imposing massive restrictions on the industry. [EPA-HQ-OAR-2009-0491-3734.1_NODA, pp.3-4]
EPA also makes mistakes at Clifty Creek about NOx emission rates. EPA listed baseline rates below that which Clifty Creek has been able to achieve based on historical, actual operation (see PTR Comments). EPA then includes 'policy' emission rates for NOx, which in most cases are close to the incorrect 'actual' base rates listed. For Clifty Creek Unit 6, however, EPA inexplicably cuts the 'actual' base rate in half for its 'policy' emission rate and uses the policy rate to estimate total emissions. EPA does not list any additional controls, or other emission reduction methods that would explain how or why Clifty Creek Unit 6 could suddenly reduce its emission rate by over 49%. As OVEC explained in its PTR Comments, there is no reason for EPA to issue a rule that is riddled with mistakes and unexplained assumptions. EPA should take a step back and take whatever amount of time is needed to correctly assess and address the impacts of this proposed rule. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
Additional Assumptions in the Model have not been Corrected [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
There are additional incorrect assumptions built into EPA's model that have not been corrected by the NODA. One glaring example is that EPA still assumes that new scrubber installations will achieve 98% removal of SO2. The reality, as discussed in OVEC's PTR Comments, is that this percentage is much higher than the rate likely to be achievable on a consistent year-round basis with no equipment problems. EPA has not corrected a basic assumption that will greatly affect allocations. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]

1 It is also worth noting that the total amount of subbituminous coal usage for the Clifty Creek units is less than the total coal usage listed in the 2014 parsed file and significantly less than the total coal usage listed in the 2012 parsed file. There is no rationale for assuming that less coal would be used in 2014 as compared to 2012, particularly when a higher heat rate is expected with subbituminous coal as compared to bituminous coal. These types of errors further illustrate the need to re-evaluate the supporting data and conclusions for the Proposed Transport Rule.
Oklahoma Department of Environmental Quality
Further, the modeling results should be used only as a guideline, not a pinpoint target. This particular model is based on guesswork regarding the price of coal and natural gas in future years, in addition to trying to predict the economic condition of the nation in the future. The IPM model run results are very erratic, retiring both coal and natural gas facilities that have no plans to retire, increasing and decreasing electricity production at various facilities, and adding solar power to Oklahoma when none has been planned. It seems that drawing conclusions based on such imprecise data is not a good practice when those conclusions will have such a substantial impact, i.e. requiring the installation of costly controls. [EPA-HQ-OAR-2009-0491-2662.1, p. 1]
Omaha Public Power District
In evaluating whether Nebraska should be included in the proposed TR, EPA modeled 2005 total emissions, purported to be from all sources, as a baseline case. EPA cites a Nebraska 2005 baseline total sulfur dioxide (S02) emission inventory of 121,589 tons/year in the preamble of the proposed TR. Of this total amount, the so-called 'nonpoint' portion modeled by EPA is 29,575 tons/year. Review of the detailed emission inventory (http://www.epa.gov/ttn/chiefinetl2005inventory.html#inventorydata ) reveals that this 'nonpoint' inventory includes S02 emissions from industrial and commercial/institutional boilers of almost 29,000 tons/year. Such boilers would really not be nonpoint sources. Most of this amount is attributed in the inventory database to subbituminous or bituminous coal usage from such boilers. In reality, EPA's TR modeling has already accounted for 'non-EGU' point source S02 emissions at 6,429 tons/year, which at least appears to be in the right ballpark, based on our review of facility-by-facility emissions included in the NEI database. This is also confirmed by the US Department of Energy, Energy Information Administration (EIA) on-line data, which shows recent (calendar years 2007 and 2008) industrial and commercial boiler coal usage in Nebraska in the range of 400-500 thousand tons/year. Based on typical sulfur levels in the Powder River Basin coal burned in virtually all of Nebraska, this is generally consistent with the 'non-EGU' emission level cited above. Thus, it appears there are approximately 29,000 tons/year of nonexistent S02 emissions (nearly 25% of the Nebraska 2005 baseline inventory) in EPA's modeled 2005 S02 inventory for Nebraska and this incorrect amount is then carried forward in EPA's analysis of the 2012 and 2014 base cases. [EPA-HQ-OAR-2009-0491-2680.1, p. 2]
The EGU 2005 base case Nebraska S02 emissions for EOUs appear to be reasonable, at 74,995 tons/year. Industry data (EPA Clean Air Markets Division, on-line Acid Rain database) indicate these emissions had increased slightly to approximately 76,000 tons/year in 2009. A new, well-controlled 663 MW coal-fired unit, Nebraska City Station Unit 2, came on line early in 2009, and may have helped produce the slight increase. A new, well-controlled 220 MW unit known as Whelan Energy Center Unit 2 is expected to come on-line in 2011, with maximum potential-to-emit for S02 of 1162 tons/year. No other proposed new Nebraska coal-fired EGUs are either permitted or under construction that would come on-line by 2014. Thus, it is very puzzling why EPA forecast Nebraska EGU 802 emissions of 120,790 tons/year in 2012 and 115,695 tons/year in 2014. These are very substantial increases above current and expected levels and are not credible. The existing units included in the 2005 inventory are mostly base-loaded and near capacity. Growth in generation over the next few years will be provided via the two new units more recently coming on-line as listed above. Because these new units are very well controlled for 802, they will contribute relatively little (approximately 3,000 tons/year) to statewide 802 emissions.  [EPA-HQ-OAR-2009-0491-2680.1, pp. 2-3]
For 'Group 2' states such as Nebraska, EPA states in the preamble (FR, Aug. 2, 2010, page 45290):
'These states are only required to make 502 reductions that could be made through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built by 2012 and (3) the use of low sulfur coal. Because those strategies were already being applied in most states covered by this rule in 2009, EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM. This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM.' [EPA-HQ-OAR-2009-0491-2680.1, p. 3]
In Nebraska, there are only two units with scrubbers, those being for the two new units described above, which are subject to stringent Best Available Control Technology (BACT) limits. Thus, there will be no 802 reductions due to Items 1) and 2) listed in the EPA preamble paragraph above. Regarding Item 3), the use of low sulfur coal, all the EGUs in Nebraska have used low-sulfur Powder River Basin (Wyoming) coal for many years, and plan to continue to do so. Coal delivery routes and purchase agreements in place are expected to facilitate the continued use of PRB coal for all the Nebraska units for the foreseeable future. Therefore, there is no justification for projecting the substantial increase for the 2012 and 2014 base cases, whether using IPM or some other projection tool or assumption. [EPA-HQ-OAR-2009-0491-2680.1, p. 3]
Furthermore, the preamble text above says EPA believes the 2009 'actual performance' is more representative of expected emissions than what EPA modeled using the Integrated Planning Model (IPM). This is supported by Attachment 1, which shows a plot of average coal sulfur (in pounds/million Btu) for Nebraska EGUs for the period 1998 through 2009, along with the values EPA used for its 2012 and 2014 impact projections. The historical values range from approximately 0.57 to 0.68 lb/mmBtu over this period, nowhere near the almost 0.9lb/mmBtu values used for EPA's 2012 and 2014 analyses in the TR proposal. [EPA-HQ-OAR-2009-0491-2680.1, p. 3, see 2680.1, p. 8 for Attachment 1]
So while EPA proposed 2012 EGU emission budgets in Nebraska approximately equal to 2009 emissions, it modeled greatly inflated base-case 2012802 emissions for Nebraska. It is not clear if the 2012 base-case S02 emissions modeled for Nebraska were based on IPM, but if they were, this seems to contradict EPA's stated intent as indicated in the preamble language cited above. [EPA-HQ-OAR-2009-0491-2680.1, pp. 3-4]
Similar to the problem outlined in Item 4, NOx emissions from EGUs are overstated. The two new coal units described above are very well controlled, and with low-NOx burner projects being required under the Regional Haze program, total EGU emissions of NO x are likely to decrease between 2005 and 2014, rather than increase slightly as forecast by EPA. [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
Given the several major emissions inventory problems identified in Items 2-5 above, EPA should therefore correct its modeling analysis for Nebraska. Emissions inventory problems of lesser magnitude in Minnesota, for the prior CAIR rule modeling analysis, resulted in the issue being remanded to EPA for further study (D.C. Circuit of the US Court of Appeals, in North Carolina v. EPA, decided July 11,2008) [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
Peabody Municipal Light Plant
EPA proposes zero NOx allocations for Waters River Unit 2 even though actual annual baseline emissions were determined by EPA to be 3.2 tons. It appears that this is because the IPM model does not project the unit to operate in 2012, which is an unfounded assumption. The lack of transparency with how the IPM model predicted that Unit 2 was not going to operate in 2012 makes it difficult to comment on any false IPM model inputs and/or assumptions. [EPA-HQ-OAR-2009-0491-3730.1 p.1]
Pfeiff, Mike
12. Base Case Year - A key step in the process of developing the Proposed Transport Rule is the Air Quality Modeling. The Air Quality Modeling process begins with analyzing existing emissions (i.e. the 'Base Case') to determine which states significantly contribute to downwind nonattainment and maintenance areas. 75 Fed. Reg. 45233. However, unlike other modeling inputs used to support the Proposed Transport Rule, which in most circumstances are based on more recent and relevant data (i.e. 2009 or even 2010), the existing emissions data, arguably the single most important data input, is based on 2005 data. The EPA cites, 'The modeling for 2005 was used as the base year for projecting air quality data for each of the 3 future year scenarios'. 75 Fed. Reg. at  42338. [EPA-HQ-OAR-2009-0491-2742.1, p.9]
In order to prevent prejudicing the results and avoided the perception of 'cherry-picking' a base year that provides a higher likelihood of achieving underlying political objectives, the EPA should use more recent emissions data. The EPA's Clean Air Markets Division produces Progress Reports each year that provide an inventory of SO2 and NOx emissions. These reports represent a summary of the unit level emissions data that in many cases is provided to the EPA at the hourly frequency. The EPA's web page currently list progress reports through 2009. (http://www.epa.gov/airmarkt/progress/progress-reports.html). [EPA-HQ-OAR-2009-0491-2742.1, p.9]
[For additional comments pertaining to Base Case Year, see pages 9-11 of this comment.]
13. Natural Gas Price Assumption - In the United States, natural gas sets the marginal cost of electricity for a very high proportion of the hours each year. In many regions of the United States natural gas already sets the marginal price of electricity in excess of 90% of time. By its very nature it is easy to see how if the Proposed Transport Rule is finalized it will increase the proportion of hours where natural gas sets the margin price of electricity across the country. In essence, the Proposed Transport Rule will make the United States more dependent on Natural Gas as a fuel for generating electricity relative to Coal. This dynamic makes the modeling results highly sensitive to the price of natural gas. Given the voluminous nature of the supporting documents there has not yet been a reasonable time period to fully read and understands the assumptions especially since the EPA only released the full Integrated Planning Model (IPM) modeling results on September 1, 2010. However my initial review of those results have revealed some troubling issues. [EPA-HQ-OAR-2009-0491-2742.1, p.11]
First, it appears that the EPA has recently shifted to a new (or substantially revised) model as part of its effort to analyze the potential effects of Proposed Transport Rule. While there nothing inherently wrong with utilizing new modeling techniques. However, I do have concerns that shifting modeling applications for a proposal of this magnitude is extremely risky. At the very minimum, the EPA should perform the analysis with the previous version of the model in parallel and make available the inputs and results of both sets of modeling to allow the public to benchmark the differences. [EPA-HQ-OAR-2009-0491-2742.1, p.11]
Second, it appears that the new modeling process is a departure from the past where EPA obtained energy commodity price inputs from the Department of Energy's (DOE) Annual Energy Outlook (AEO) which serves as US Government's official energy forecast. Instead, it appears the many of the key modeling assumptions embedded in the in the IPM that were used to evaluate the Proposal came from a 3rd party energy consulting firm commissioned by the EPA. This raises the following questions:
a. Why did the EPA choose to populate the IPM with inputs from 3rd party consultants instead of utilizing inputs that were sourced from, or at least internally consistent with, the DOE's official and most recent AEO?