Amount of information does not allow the public adequate time for comprehensive and meaningful comments: AEP requested twice, once for the original proposed rule and again when the NODA was published, to have the comment period extended at least 60 additional days, to November 30. The Proposed Transport Rule 60-day comment period did not allow an in-depth review of the sheer number of pages of technical data that supported the development of the rule. That was compounded by EPA publishing an additional 3500 pages of data in the NODA that changed some of the model costs and corrected some unit specific information. Along with not allowing adequate time for the public to understand and evaluate the work by EPA, the information provided in these published notices and used as a basis for the modeling is incorrect. When connected, the models will need to be rerun and may result in changes to the significance determination, the allocation budgets, and different operating scenarios for the many utility boilers affected by this rule. We request that EPA take the comments from the public, correct the inaccuracies of the inputs to the models, rerun the models then use that information to develop and publish as a supplemental notice a rule that meets the requirements of the court and continues to utilize the CALR budgets and timing to attain the goal of controlling emission transport that may affect the NAAQS.[EPA-HQ-OAR-2009-0491-3719.1_NODA, p.2]
Data and Assumption Comments
The NODA does not provide enough information for companies to properly evaluate how the changes will affect the allowance allocation budgets nor do they provide information on whether there are any changes to the significant contribution evaluation performed in the original proposed rule. Furthermore, AEP believes that some data in the NEEDS v4.10 database is incorrect. The NEEDS database lists certain units with inaccurate emission controls. Additionally, the IPM model structure does not take into account all necessary unit specific operating constraints, specifically those relating to fuel suitability and unit availability. Furthermore, EPA's data on purportedly 'actual' costs of scrubbers and SCRs are lower than actual industry and AEP-specific experience. While the agency attempted to provide an updated NEEDS database along with sample IPM runs using the new data and model structure, the use of incorrect data and lack of documentation as to how the proposed rule will be affected does not provide the public with any meaningful results. [EPA-HQ-OAR-2009-0491-3719.1_NODA,p.3]
Big Rivers Electric Corporation
NEEDS Data Issues
-Modeled fuel for Wilson is Petroleum Coke only.  Wilson has burned a combination of Southern Illinois Basin bituminous coal and petroleum coke.
-The Wilson permitted emission rate for SO2 is listed at 0.6 lbs/mmBtu.   The actual permit limit is 1.2 lbs/mmBtu.
-The HMP&L Station Two Henderson units (H1 and H2) and the Kenneth C Coleman unit (C1, C2, and C3) all include Wet Scrubbers.  This fact was not included in the Hg EMF Inputs.
-The SCR for the D B Wilson unit (W1) is shown to have come online in 2001.  It came online in 2004.
-The SCR for the HMP&L Station Two Henderson unit (H1) is shown to have come online in 2002.  It came online in 2004.
-The SCR for the HMP&L Station Two Henderson unit (H2) is shown to have come online in 2002.  It came online in 2004. [EPA-HQ-OAR-2009-0491-3720.1_NODA, p.2]
Parsed Data Issues
-The D B Wilson unit shows zero (0) bituminous fuel use.   The unit in fact burns either a combination of Southern Illinois Basin bituminous coal and petroleum coke or Southern Illinois Basin bituminous coal only.
-The Robert A Reid combustion turbine (Gen2) shows zero (0) NOx and SO2 emissions indicating they will not be utilized.   The unit is necessary to meet our forecasted demand and will be utilized into the future.  [EPA-HQ-OAR-2009-0491-3720.1_NODA, p.2]
Buckeye Power, Inc.
3. Data and input errors should be corrected.
We plan to submit comments on the NODA that will further address data and input errors present in the additional and updated data and modeling, which EPA provided with the NODA. Buckeye notes the following, however, with respect to the initial data and modeling EPA provided with the CATR proposal: [EPA-HQ-OAR-2009-0491-2710.1, p.6]
a. Cardinal Unit No. 2, Brilliant, Ohio.
Cardinal Unit No. 2's capacity is incorrectly listed as 590.1 MW. In fact, it is 600 MW (similar to Cardinal Unit No. 1). In addition, Cardinal Unit No. 2 was included in a NSR Consent Decree and therefore should be classified as a non-dispatchable scrubber. [EPA-HQ-OAR-2009-0491-2710.1, p.6]
b. Cardinal Unit No. 3, Brilliant, Ohio.
Cardinal Unit No. 3's capacity is incorrectly listed as 619.6 MW. In fact, it is 630 MW.
In addition, Buckeye's Cardinal Unit No. 3 SO2 scrubber is not required to be completed until the end of 2012, rather than in 2010 or 2011 as EPA's model estimates. Furthermore, Buckeye's Cardinal Unit No. 3 scrubber is not scheduled to be completed until early 2012, and it could be delayed if there are problems in the construction process. Accordingly, EPA's modeling and methodology should assume a December 31,2012 installation date for Buckeye's Cardinal Unit No. 3 SO2 scrubber.
The Cardinal Unit 3 FGD System was also included in a NSR Consent Decree; therefore, it should also be classified as a non-dispatchable scrubber.
Finally, the Controlled NOx Base Rate of 0.030 lbs/mm BTU that was achieved during the 2006 ozone season was an extraordinary performance. This NOx emission rate remains the lowest seasonal rate ever achieved by any SCR for which we have data. This emission rate is not sustainable over the long term and allowance allocation baselines need to be representative of the performance over the entire catalyst life cycle (3-5 years). The Controlled Annual NOx rate for this unit should be 0.05 lbs/mm BTU, similar to the assumed rate for new SCR equipment. [EPA-HQ-OAR-2009-0491-2710.1, p.6]
c. Greenville Station, Greenville. Ohio.
The Greenville Station units are peaking units. Nevertheless, EPA proposes to grant only 14 NOx emission allowances to them based upon historic emissions, which are inherently unreliable given the intermittent and variable operation of peaking units. However, even using historic emissions as a baseline, the Greenville Station units have been allocated less allowances than they have historically needed to operate and certainly below their permitted levels. This is arbitrary and unreasonable. These units are critical to grid reliability and must be allocated sufficient NOx emission allowances to operate when and as needed to meet peak load demands. In addition, natural gas-fired peakers are classified as a minor sources. Such units should receive allocations equal to the lesser of actual or permitted emission limits. [EPA-HQ-OAR-2009-0491-2710.1, p.7]
d. Robert P. Mone Plant, Convoy, Ohio.
EPA proposes to grant the Mone facility Zero NOx emission allowances despite the fact that it has been operating since 2002. This constitutes either a plain error, or a shocking example of the shortcomings of EPA's modeling-based allocation scheme. These units, by the very nature of being peakers, only operate when needed. These units are likewise critical to grid reliability. Moreover, these units are classified as a minor source, and therefore should receive allocations equal to the lesser of actual or permitted emission limits. [EPA-HQ-OAR-2009-0491-2710.1, p.7]
5. EPA's allocation scheme is unreasonable and arbitrary.
a. EPA's allocation methodology and modeling is not transparent and parties have not been given sufficient time to evaluate it.
EPA's methodology should be transparent and affected parties should be given adequate opportunity to understand EPA's methodology and data inputs. We understand that EPA released additional and updated CATR program-related methodology and supporting data on September 1 ('Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transportation of Fine Particulate Matter and Ozone' ('NODA'). Parties have only until October 15 to comment on the NODA. This is clearly not enough time to evaluate such a complicated methodology. Furthermore, there was only one month between release of this data and when comments are due on CATR itself. [EPA-HQ-OAR-2009-0491-2710.1, pp.7-8]
The updated modeling assumptions are flawed; consequently, the CATR is likely to remain arbitrary and capricious, an abuse of discretion, and otherwise not in accordance with the law. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.1]
We believe that EPA should support and encourage maximum utilization of fully controlled units, such as Buckeye's, as compared to uncontrolled or lesser-controlled units. It appears that CATR, particularly after application of the updated model results, does not achieve this goal. Based upon Buckeye's review of the NODA data, operation of Buckeye's coal-fired units will be constrained even more so than under the NEEDS v. 3.02. This is bad public policy and contrary to law. Units employing BACT should not be constrained from normal operation to meet load responsibilities and to support grid reliability. [EPA-HQ-OAR-2009-0491-3724_NODA, p.2]
Heat Input and Operability Factors Utilized By EPA Are Arbitrary and Unreasonable
The assumed availability of Buckeye's coal units has been reduced in the updated model assumptions as compared to the NEEDS v. 3.02 model. This constitutes an abuse of EPA's discretion and renders the CATR arbitrary, capricious, and not in accordance with law since Buckeye's fully controlled units should be dispatched first, ahead of uncontrolled units, to meet load and support grid reliability. It appears that EPA may be limiting existing unit availability assumptions based upon certain historic capacity factors. However, depending on the circumstances, historic performance can be, and in this instance is, an inappropriate basis for setting emission limits. Fully controlled baseload units, are the most environmentally friendly and cost effective units to meet load requirements. It is contrary to the Clean Air Act permitting programs and objectives for EPA to arbitrarily constrain these units in lieu of uncontrolled units. [EPA-HQ-OAR-2009-0491-3724.1_NODA, pp.2-3]
EPA's revised model's use of historical capacity factors for Buckeye's Cardinal Units translates into an assumed 73% availability for Buckeye's Cardinal Units, which is less than the 85% assumed availability for new units. It is likewise arbitrary and capricious for EPA to conclude that Buckeye's units, which are fully controlled for S02 and NOx, should have an assumed availability less than a similarly equipped new unit. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.3]
Moreover, Buckeye's Cardinal units are part of the PJM Interconnection, LLC, which is a FERC approved regional transmission organization, or 'RTO.' As a member of the PJM RTO, Buckeye has daily 'must offer' requirements, and PJM, not Buckeye, decides which units must be dispatched to support regional grid reliability and to support economic dispatch of units within the RTO based upon the day ahead power 'bids.' EPA's proposed heat input and operability limits for Buckeye's BACT-controlled units conflicts with the grid reliability concerns of FERC and PJM, which assume a fully controlled unit is available for dispatch to support grid reliability and economic dispatch. There is no reason why Buckeye's fully-controlled units should not be so available. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.3]
Buckeye's NOx and S02 Rates Under CATR Would be Unreasonably and Arbitrarily Low
Buckeye's Cardinal's Unit 3 NOx rate is reduced under the updated model beyond the already impermissibly low rate ascribed under the NEEDS v. 3.02. EPA's calculated annual NOx emission rate of 0.023 lbs/mmBtu appears to be one of the lowest NOx rate assumptions in the United States for coal fired generation units. Buckeye reiterates the point made in its CATR comments that it is being punished for having already installed high performing SCR systems. Compounding the unfair impact, EPA is using one year (2007) as the base year for its NODA calculations. It is unrealistic, unfair, an abuse of EPA's discretion, and arbitrary for EPA to use one year's emissions data as the basis to constrain future emissions. It is particularly arbitrary and capricious as applied to Buckeye, as Buckeye's Cardinal 3 SCR equipment had its highest annual control efficiency ever in 2007. An 0.023 lbs/mmBtu NOx rate is inconsistent with historical and projected future Buckeye operations and not achievable during year round operation. This illustrates the inequity of using a single test year as the basis for allowance allocations. Buckeye should not be punished by having its allowance allocations substantially reduced because EPA uses a single test year and the highest performing year ever for Buckeye's SCR system. This is arbitrary and unreasonable, as Buckeye cannot be expected to sustain that level of control systems performance on a year-to-year basis. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.4]
It appears that Buckeye's S02 rate for its Cardinal Units also has been substantially reduced as compared to the S02 emissions rate under the NEEDS v. 3.02. The S02 emission rate in the NEEDS v. 3.02 was 0.218 as compared to 0.087 in the NODA. This constitutes a 60% reduction. Given the fact that Buckeye already employs BACT emissions controls, Buckeye can only conclude that this reduction reflects an erroneous EPA assumption about fuel switching. The lPM model appears to contemplate full switching to low sulfur coal in 2012; however, this cannot happen in the real world. First, Buckeye (like many companies) has long term high sulfur coal contracts which have minimum tonnage obligations, in place through December 31, 2017. Buckeye would have to breach those contracts or pay and take for tons not needed, if Buckeye is not allowed to burn high sulfur coal with its scrubbers. Second, many coal-fired boilers are limited to a minimum specification for sulfur content due to their boiler configuration, their ESP and/or their air permit limitations (e.g., use of low sulfur coals at certain units can cause opacity to exceed permit limits). Buckeye's scrubbers were designed to bum high sulfur coal. Design changes and additional expense may need to be incurred to allow its scrubbers to operate exclusively with low sulfur coal. Third, Buckeye is committed to having the option of using locally mined Ohio coal to operate its units. If low sulfur coal is required by these regulations, Buckeye would not be able to bum local Ohio coal; consequently, local jobs would be lost and the local economy would be damaged. For all of these reasons, at a minimum, Buckeye should be allowed to burn Ohio coal for the benefit of the local economy and Buckeye's member consumers. [EPA-HQ-OAR-2009-0491-3724.1_NODA, pp.4-5]
Buckeye suggests that at ~ minimum its NOx emission rate should be set at EPA's emission rate floor of 0.06 for NOx. Buckeye believes that the most reasonable and appropriate S02 emission rate floor would permit full operation of BACT -controlled units using locally mined high sulfur coal and the fact that the scrubbers have been designed for this local Ohio coal. There is no reason for Buckeye to be punished for having already installed high performing emission controls by having its NOx emission rate set at a rate lower than EPA's own emission rate floor. Setting emission rates based upon Buckeye's high performing equipment and highest performing year is entirely arbitrary and capricious as it sets a ceiling on emissions that cannot be met on a regular basis with normal operations, even with BACT already installed. This is arbitrary, capricious, and not in accordance with law and will result in unit curtailments or the purchase of high cost replacement power. [EPA-HQ-OAR-2009-0491-3724.1_NODA, pp.5-6]
As discussed in Buckeye's comments on the proposed CATR, Buckeye has acquired, at a cost of approximately $25 million, S02 allowances that may not be used (and thus will be rendered worthless) under CATR. This would constitute a 'taking' in violation of the Fifth Amendment of the U.S. Constitution. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.6]
Additional Factual Corrections
There remain a number of factual errors in EPA's NEEDS v. 4.10 database with respect to Buckeye which must be corrected. EPA indicates that the Cardinal Unit 3 scrubber will be operational in 2010. That is incorrect; the Cardinal Unit 3 scrubber is expected to start up by December 31,2012. Also, Buckeye's Cardinal Unit No.2 and 3 scrubbers are non-dispatchable because they are included in a NSR Consent Decree. Finally, contrary to the NODA data, Buckeye's Cardinal Unit 2 does currently have a wet scrubber installed and in operation. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.7]
EPA should withdraw and reconsider CATR, and re-visit and revise its NEEDS v. 4.10 assumptions and inputs. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.7]
Capital Power Corporation
For example, on September 1, 2010, EPA issued a Notice of Data Availability, in which it updated the data which defines availability of plants, with comments due October 15, 2010. In one case, data for one company indicated 79% availability for a facility with a contractually obligated 97% availability. Clearly, EPA's data will require close inspection and analysis by affected sources as all such data affects the implementation of the proposed rule. EPA needs to allow companies the opportunity to review the Rule and related models and data and comment on as a single exercise. [EPA-HQ-OAR-2009-0491-2753.1, p.3]
Clean Air Task Force
CATF makes the following specific comments on the NODA and the associated documentation for IPM v.4.10 (the "Documentation"): [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.2]
The Documentation indicates that dry sorbent injection ("DSI") is not among the pollutant control technologies available for deployment in IPM.  See Documentation at Table 1-2 and Documentation at pages 5-1 and 5-2 Prior analysis by EPA indicates that in some cases, at least, DSI systems can have "significantly lower capital and annual costs than wet systems" for SO2 control, however, and "install easily and use less space" and are therefore "good candidates for retrofit applications."  This potential is reflected in recent compliance planning activity in the utility industry.  According to the Institute of Clean Air Companies, DSI may also offer reduced-cost "multi-pollutant control opportunities by combining acid gas, SO2, particulate control, and air toxics, including mercury." Bundling hazardous air pollutant control with lower cost sulfur control on existing coal units could significantly change the economics of Transport Rule and MACT compliance, and EPA should include DSI in IPM to reflect this possibility. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.2]
The Documentation indicates that carbon capture and sequestration ("CCS") is not among the carbon dioxide emissions reductions options available for existing and new combined cycle power plants burning natural gas ("NGCC") in IPM v.4.10.  See Documentation at Table 4-7 and related discussion and Documentation at Table 4-13 and related discussion.   Analysis by the Department of Energy suggests that the cost of electricity produced from NGCC with CCS may be less than the cost of electricity produced by coal power plants with CCS when natural gas prices are comparatively low, however, so omission of an "NGCC with CCS" reduction option in IPM could both overstate the costs of compliance with emission reduction mandates and significantly misrepresent the universe of potential compliance solutions available to policy-makers.  This is especially important as the Documentation indicates there are roughly 180 billion watts ("GW") of combined cycle capacity installed in the United States (compared to roughly 305 GW for coal power) and another 25 GW planned-committed through 2011. See Documentation at Tables 4-3 and 4-12. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.2]
The Documentation indicates that relatively tight constraints have been placed on deployment of CCS and nuclear power technologies in IPM.  Total deployment of CCS would be limited to just under 50 GW through model run year 2030, for example, in the event that no nuclear power is built during that time, and total deployment of nuclear power would be limited to just under 37 GW during the same time period if no CCS is built.  If some of both types of technologies are built, a combined constraint would apply in order to reflect bottlenecks in engineering and equipment supply chains.  See Documentation at page 3-21 and Appendix 3-7.    While EPA has provided some basis for the imposition of these constraints, they are at odds with historical precedents including the data provided in the Documentation itself, which indicates that during the `boom' years in nuclear power development in the US roughly 5 GW per year of new capacity were installed here.  See Documentation at Figure 3-2.   If such historical peak rates were applied to CCS and nuclear deployment in IPM, the constraints could well be looser.   Recognition of today's global context for engineering and manufacturing, as well as the potential for modular facility construction, could also result in significantly looser deployment constraints for these technologies. [EPA-HQ-OAR-2009-0491-3749.1_NODA, pp.2-3]
The Documentation indicates that IPM includes only a single vintage of performance and cost assumptions for CCS technology (for the period 2012 through 2054), and therefore does not reflect the likely possibility that costs and performance of CCS will improve over time as the technology is widely deployed.   See Documentation at Table 4-13 and related discussion.  This treatment is at odds with current literature on technology learning rates, which suggests that for CCS costs could decline significantly as capacity is installed. 6 [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]
The Documentation suggests that for the Base Case analysis, at least, IPM is not able to deploy new electricity transmission between generators and load centers.  See Documentation at page 2-10.   If maintained in future runs, such a deficiency is likely to significantly limit the usefulness of IPM for analysis related to technologies with a high degree of spatial dependence, such as renewable power and CCS generally, and also to potential breakthrough technologies that might be analyzed in future years (such as those discussed in paragraph 6 below). [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]
The Documentation does not reflect several emerging technologies that could significantly impact future CAA regulation compliance options, costs and impacts. These include underground coal gasification with carbon capture and sequestration (UCG/CCS) 7 and innovative, modular compressed air energy storage technology. While both of these technologies have geographic constraints for which complete data may not yet be available, these technologies could be included in a preliminary fashion to provide insight into how important they might be for reducing air pollutant emissions. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]
In conclusion, while CATF generally supports the appropriate use of IPM v.4.10 in the Transport Rule and future rulemakings involving the power sector, we urge EPA to improve this IPM version in accordance with the above comments. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]

 6 See, e.g., Rubin et al., "Use of experience curves to estimate the future cost of power plants with CO2 capture,"  International Journal of Greenhouse Gas Control, 2007, 188-197.
7 See CATF (2009), "Coal Without Carbon: An Investment Plan for Federal Action," available at: http://www.catf.us/resources/publications/files/Coal_Without_Carbon.pdf.
Cleco Corporation
EPA's Projections Are Inconsistent with FERC-Commissioned Projections [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
EPA's projected heat inputs and resulting capacity factors for Evangeline are inconsistent with recent projections in connection with a study by the Federal Energy Regulatory Commission (FERC). FERC is currently analyzing the costs and benefits of Entergy and Cleco Power (Cleco's regulated electric utility business) joining the Southwest Power Pool (SPP) regional transmission organization (RTO). The FERC agreed to fund a Cost Benefit Analysis (CBA) to study the costs and benefits of Entergy and Cleco Power joining the SPP as full transmission-owning members with their transmission facilities under SPP operational control. The CBA was performed over a seven-month period, and included an open and collaborative discussion with stakeholders of the study framework, modeling approach, input assumptions, interim results, and qualitative issues throughout this period. Based on FERC's analysis, performed by Charles River Associates and Resero Consulting, if Entergy and Cleco Power do not join the SPP RTO (which is the "Status Quo Case" depicted in the attached Exhibit 1) Evangeline's capacity factor is projected to be approximately 25%, which is higher than both of EPA's IPM projections. These projections call into question EPA's methodology. [EPA-HQ-OAR-2009-0491-3727.1_NODA, pp.2-3]
In addition, this study evaluated the implications for Evangeline if Entergy and Cleco Power were to join the SPP RTO (which is the "Join SPP Case" depicted in the attached Exhibit 1). In that case, the FERC study shows Evangeline with capacity factors ranging between 50% and 60%. This analysis is a great example of how externalities  -  two regulated utilities joining an RTO  -  dramatically impact capacity factors and corresponding emissions. We believe it is imprudent to effectively limit the output of Evangeline in one regulatory arena, i.e., environmental, when it is significantly impacted by another arena, i.e., FERC. The FERC study suggests that IPM Version 4.10 is not necessarily the model of choice. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
EPA's IPM Projections Would Effectively Limit Evangeline's Operations [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
Evangeline is already a low emitting facility equipped with state of the art pollution controls for NOx. The availability of allowances will likely be very limited, particularly in the first few years of the program. EPA itself stated that it expects very little if any trading as part of this rule. As a result, prudent operators cannot rely on the possibility that allowances might become available for purchase for purposes of compliance planning. Therefore, Cleco Midstream's only assured compliance alternative is to plan to reduce unit run time to stay within its allowance allocations if necessary to comply with this rule. A severe under-allocation of allowances would make it difficult for this low emitting unit with state-of-the art pollution controls to comply. Yet it appears that Evangeline is at risk of being under-allocated, based on our understanding of the data provided in this NODA. Limiting the emissions of Evangeline in this manner could require this facility to seek market allowances that may be difficult to obtain. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
Cleco Midstream is deeply concerned that, with EPA's addition of new data and a new version of IPM, a viable low emitting electric generating unit can go from 491 annual NOx tons to a mere 47 tons  -  a tenfold reduction. Because EPA has refused to issue a supplemental rule with updated allowance allocations, for compliance planning purposes, Cleco Midstream has to assume that the projected NOx tons in the IPM Parsed File for Base Case 2012 will correlate to the Agency's annual NOx allocation for this facility, which is simply unworkable. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
If EPA insists on retaining the FIP approach in this transport rulemaking, then Cleco Midstream urges EPA to evaluate these impacts and substantially revise its methodology for allocations and the allocations themselves. As applied to facilities like Evangeline, EPA's scheme causes great economic inequity with no discernable environmental justification. [EPA-HQ-OAR-2009-0491-3727.1_NODA, pp.3-4]
IPM is a linear programming model that generates optimal decisions under the assumption of perfect foresight and it determines the least-cost method of meeting energy and peak demand in a perfect dispatch world. Relying this heavily on the IPM 4.10 assumptions to formulate such rigorous federally enforceable environmental requirements is arbitrary and capricious on EPA's part and does a disservice to the customers of regulated utilities and wholesale generators. In Louisiana, there is anything but perfect foresight in the power sector and electric generating units are not dispatched purely on an economic basis. Transmission constraints, fuel limitations, voltage issues, reliability concerns, contractual obligations, and other issues all contribute to dispatch decisions of a particular generating unit. IPM 4.10 is ill-suited to be the basis of this rule because the IPM model is only as good and accurate as the inputs that go into it, and in this case the inputs will vary too substantially from the model assumptions to be solely relied upon. Most noted sources of natural gas pricing models such as the forecast in EIA's AEO have often changed their base case assumptions over time as the economy, population, supply, demand and other factors change. In fact, the EIA's AOE (which EPA uses as a reference natural gas price case) often adjusts its natural gas forecast price from year to year, and sometimes the change is drastic. There is an apparent disconnect with the proposed rule if it is setting the basis for a long term rule with a 2010 projection without adjustments or off-ramps in the later years, knowing full well that these forecasted inputs will change as time goes on. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
Corrections to Evangeline Power Station's Unit Performance Data [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
In the NEEDS database associated with this NODA, EPA has indicated that the heat rate from Evangeline Power Station is 8,760 btu/kw. As mentioned previously, Evangeline is a state of the art combined cycle unit with a proven average heat rate of 7,450 btu/kw; a 15 percent heat rate improvement over the data in the NEEDS file. This performance is verified by unit performance test run by the facility in July of 2009 and attached in Exhibit 2. [EPA-HQ-OAR-2009-0491-3727.1_NODA, pp.4-5]
In the NEEDS database associated with this NODA, EPA has indicated that the Corrected NOx Base Emission Rate from Evangeline Power Station is 0.0213 lbs/mmBtu. However a review of CAMD data suggests that the reported emission rate is well above the projected emission rate in the NEEDS file. In fact, depending on the specific unit at Evangeline, in the period from 2005  -  2009, the NOx rate ranges from a minimum of 0.03 lbs/mmBtu to a maximum of 0.07 lbs/mmBtu. If in fact EPA uses this rate to form the basis of NOx allocations, this data should be corrected. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
Other Examples of Incorrect/Misapplied Data [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
In this limited time, Cleco Midstream has attempted to review the proposed rule and all the technical provisions of IPM 4.10 contained therein, but it was not practical to review every data set and review, apply and understand all the IPM model applications. As such, Cleco Midstream fears that there are technical data errors that have been missed or overlooked in this limited timeframe for review. One example is that of emission allowances granted to units that cease to exist or are not currently operating. Washington Parish Energy Center (WPEC) (ORIS55486) located in southeast Louisiana is one such example. In IPM Version 3.02, WPEC was granted some 393 annual NOx allowances. These allowances were granted to a non-operating unit that isn't likely to operate in the future. In fact, a search of EPA's CAMD database turned up no operating data for this facility. Further, using IPM version 4.10, it appears that EPA intends to grant even more allowances to this same unit than it did in IPM Version 3.02. As best as we can ascertain, WPEC will be granted some 470 allowances. That's an additional 77 annual NOx allowances. Again, not knowing the black box calculations of the IPM Version 4.10, Cleco Midstream assumes that the apparent increase in annual NOx allowances to WPEC is attributable to the IPM 4.10 model dispatching the facility even more than in the previous 3.02 version. On what basis was this unit dispatched even more? With this type of apparent oversight and its significant impacts, we contend that the use of IPM Version 4.10 is not the proper method of basing this regulatory program. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
State Budget Issues [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
From a review of the parsed files in IPM version 4.10, it appears that Louisiana's annual state NOx budget has been reduced from 43,946 allowances to 38,804 allowances. It is difficult to understand the methodology that EPA will employ to determine a state's budget. Presumably, EPA had determined using version 3.02 that limiting Louisiana's EGU's to 43,946 tons per year of NOx was sufficient to reduce its impact on maintenance or significant contribution to PM 2.5 nonattainment. By EPA's own modeling methodology, we would disagree that an additional 11,142 reduction is required. Cleco Midstream simply does not have enough time to determine what changed in the model to cause such a drastic further reduction. We note here that several comments filed on the October 1, 2010 for the proposed Transport Rule addressed and substantiated the insignificant contribution of nitrates to PM 2.5; yet another reason not to require an additional 11,142 ton state budget reduction. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
The NODA provides enough information for us to know that our prior analysis is now irrelevant. With EPA's adoption of a new version of IPM and new data, the state budgets and unit allocations we reviewed are now obsolete. Unfortunately, that is about all we can determine from the NODA. EPA does not provide  -  and has indicated it will not provide  -  the numerous modeling runs and summary spreadsheets needed for us to determine what emissions will be allowed from EGUs in Louisiana and what portion of the permissible emissions are attributed/allocated to Cleco. Because the Agency does not intend to provide revised state budgets and unit allocations, commenting on compliance issues is nearly impossible. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.2]
Now, we no longer have before us enough information to evaluate: what is and is not a receptor, whether Louisiana is linked to any receptors, what emission reductions EPA assumes will be available at various cost per ton removal thresholds or the resulting air quality impacts, what breakpoints will define significant contribution and interference with maintenance, or whether Louisiana qualifies for the Group 2 off ramp. Put simply, the rule we commented on is rendered obsolete by the NODA. And now we struggle to comment with incomplete information on what the new rule will be. This undermines our ability to provide meaningful comments on compliance feasibility or the rule's impact on electric reliability. Instead, we are left commenting on broad principles (e.g., to auction or not to auction) and minute details (e.g., a single unit's reported heat input for a single quarter, math errors, or control assumptions for a single unit). [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
This proposed rule is simply too important to promulgate without allowing for comprehensive, well informed public input and comment. We urge the Agency to publish a supplemental rule for comment. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
EPA Must Provide Industry With Additional Information for Planning/Forecasting Purposes. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
EPA's refusal to provide revised state budgets and unit allocations until the rule is finalized makes compliance planning impossible. EPA must advise states and industry of which programs they are in, what their state budgets will be and what their unit allocations will be well in advance of the compliance deadlines. Most, if not all, of the numerous compliance strategies EPA identifies (installing controls, switching fuels etc.) are not available with the short notice EPA intends to provide. State environmental agencies, the electric power industry, the coal and gas industries and the transportation industries require a longer lead time for planning. They are massive industries with enormous responsibilities and lengthy planning horizons. They cannot be expected to respond to such abrupt regulatory and policy shifts without sufficient notice of the critical information needed for planning purposes  -  in this case the state budgets and unit allocations. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
IPM 4.10 Leads to Unrealistic Results. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
The most telling sign that these projections are inadequate for establishing state budgets and unit allocations is the outputs themselves. EPA's projections for 2012 are wholly unrealistic. With respect to Cleco units alone, EPA's projections are significantly different from historical dispatch or from what common sense dictates future dispatch will be. For example, two of our coal fired power plants Rodemacher 2 (6190_B_2) and 3 (6190_B_3A and 6190_B_3B)) are projected by IPM to operate at about 49% (Rodemacher 2) and 27% (Rodemacher 3) capacity. One of these units, Rodemacher 3, was only recently brought online. Like all base load investments, Cleco, with Louisiana Public Service Commission approval, invested significant capital costs to bring the unit online. To recover those costs and for Louisiana rate payers to get the full economic benefit of their investment, these units must and will run at significantly higher capacity factors. [EPA-HQ-OAR-2009-0491-3726.1_NODA, pp.5-6]
These projected capacity factors are also way out of line with the historical capacity factors for our Louisiana coal fired generation. Since 1999 our Dolet Hills and Rodemacher 2 units have an average capacity factor of 74%. Rodemacher 2 alone has an average capacity factor of 69% since 1999, which is 140% of the capacity factor EPA projects it to have in 2012. In 1999, when natural gas prices were near record lows, these units averaged 68% capacity. Even in 2009, the worst economic recession since the great depression, these two units averaged 74.5% capacity. See Table 2 below. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.6; see p.6 of this comment summary for Table 2 entitled, Annual Capacity Factors for Cleco Power's Dolet Hills and Rodemacher 2 Facilities (1999 to 2009)]
Coal Utilization Research Council
The potential rate of introduction of CCS technology, both at greenfield and at retrofit sites, is an important issue. EPA's IPM analysis of HR2454, for example, placed a "joint constraint" on new nuclear and CCS-equipped capacity. 3 The only constraints imposed on CCS deployment in the current IPM documentation are "Capital Cost Adders" which would increase the cost of a technology if an assumed base level of capacity addition is exceeded in a given year. These adders appear to provide very little real constraint and EPA should develop and offer for comment a more rigorous approach to address limits to the rate of introduction of CCS technology.
The capital cost estimates of retrofit CCS (IPM documentation, Chapter 6) "are based on the cost reported for Case 1" of the DOE/NETL Conesville report. That report reached an incremental capital cost of $1319/kW, whereas the IPM estimate is $1972/kW. Although we support the use of higher estimate for early CCS deployment 4, the documentation should explain how the NETL figure was modified to arrive at the IPM number. The IPM O&M estimates for retrofit differ by a factor of as much as 6 with the DOE/NETL report cited as a basis for those numbers. The reasons for such a large difference should be explained in the documentation.
Because CCS is an emerging technology, and because significant R&D is underway in the US and globally to reduce the cost of this technology, it can be assumed that the "Nth of a kind" unit will cost less than "1st of a kind" units, and that the technology will go through generic generations, with progressively better performance and lower cost. This is perhaps the most critical issue associated with projecting deployment costs for CCS. The IPM documentation provides no discussion of how the model's costs for CCS will evolve over time, or with increasing deployment, and implies that technology costs are fixed within the model. This is a particularly important issue for greenfield units, because the model's costs are based on "Nth of a kind" configurations, but the baseline projections show very little new coal capacity of any kind being built. 5 In other words, according to IPM, we may not reach "Nth of a kind" economics for greenfield units within the model's time horizon. The model documentation should address the factors influencing changing CCS economics over the model's time horizon, and incorporate estimates of the impact of those factors.
The evaluation of CO2 transportation (pipeline) costs states that there are large economies of scale associated with transporting CO2. However, achieving those economies of scale means that multiple capture projects would need to collaborate on permitting and constructing a pipeline. This shared approach seems particularly unsuited to greenfield applications of CCS, given the relatively small number of new coal units projected by IPM prior to 2030.
IPM provides cost and performance assumptions for both greenfield and retrofit coal-based power generation. The documentation has omitted analogous information for systems fueled by natural gas; is there a reason why EPA omitted this information? This type of information is readily available from the same sources cited by EPA in EPA's development of the coal-related parameters. 6

3 Supplemental EPA Analysis of the American Clean Energy and Security Act of 2009, Appendix, USEPA, January 29, 2010.
4 The IPM value is consistent with a recent DOE/NETL report which evaluated the cost to retrofit CCS on a subbituminous subcritical pulverized coal unit ($1999/kW). Assessment of Power Plants That Meet Proposed Greenhouse Gas Emission Performance Standards, DOE/NETL-401/110509, November 5, 2009.
5 EPA's Base Case IPM runs for the Transport Rule show no new coal capacity commencing operation between 2012 and 2030, other than 2GW of coal w/CCS built with federal subsidies. See http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html.
6 For example, Cost and Performance Baseline for Fossil Energy Plants, Vol.1., DOE/NETL-2007/1281, May 2007, subsequently cited in these comments as the "Baseline Bituminous report"; or Assumptions to the Annual Energy Outlook 2010, (Table 8.2) USEIA, DOE/EIA-0554(2010), April 2010, subsequently cited in these comments as "EIA AEO-2010 assumptions document".
Cogen Technologies Linden Venture, LP
D. Facilities Should Have the Opportunity to Correct Any Erroneous Data Relied Upon as the Basis for Establishing Unit Allocations
The foregoing errors illustrate how small anomalies in the data and assumptions can have drastic consequences in IPM's projections at the level of the individual unit. Before relying upon IPM projections demonstrably at odds with historic dispatch for individual units, EPA must at the very least provide facility owners with the opportunity to review and correct the inputs to IPM. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Linden Cogen considered how EPA could have come to assume a heat rate more typical of a simple-cycle combustion turbine for each of Linden Cogen's generating units. The supporting documentation for EPA Base Case v.4.10 suggests that heat rates used within IPM were derived from AEO 2008, as follows: [EPA-HQ-OAR-2009-0491-2712.1, p.12]
The heat rates in EPA Base Case v.4.10 are based on values from AEO 2008. These values were screened and adjusted using a procedure developed by EPA to ensure that the heat rates used in EPA Base Case v.4.10 are within the engineering capabilities of the generating unit types. Based on engineering analysis, the upper and lower heat rate limits shown in Table 3-10 were applied to coal steam, oil/gas steam, combined cycle, combustion turbine, and internal combustion engines. If the reported heat rate for such a unit was below the applicable lower limit or above the upper limit, the limit was substituted for the reported value. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, EPA Clean Air Markets Division, August 2010, Table 4-1, Data Sources for NEEDS v.4.10 for EPA Base Case v.4.10, 3-17. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Linden Cogen examined the referenced publication - AEO 2008 - and can identify no instance wherein it provides facility-specific heat rate information that EPA could have relied upon to populate the NEEDS database. In light of this, Linden Cogen assumes that EPA did not rely upon AEO 2008 for the unit-specific heat rates appearing within NEEDS, but rather to establish the upper and lower limits of heat rates for various 'generating unit types'. Id. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Apart from the section quoted above expressly addressing the source of heat rate data, the supporting documentation for EPA Base Case v.4.10 suggests that the heat rates appearing within the NEEDS database were derived from information submitted by electric generators to the Energy Information Administration ('EIA') on Form 860. 8 Linden Cogen examined its historic submittals on EIA Form 860 and believes that the information reported there might have been the source of the erroneous heat rate assigned to its generating units. Linden Cogen has historically reported the gross heat rate for each combustion turbine and steam turbine separately, rather than a combined cycle heat rate. Thus, if a particular combustion turbine has demonstrated that it can generate a kilowatt of energy from a given number of British thermal units of natural gas in performance testing, Linden Cogen reported that number as the heat rate to EIA, irrespective of any useful thermal energy derived from use of combustion turbine exhaust to generate steam and additional power. Similarly, for its three steam turbines, Linden Cogen has historically reported the gross heat rate of each steam turbine as confirmed by performance testing that measures the amount of thermal energy provided to the steam turbine and the corresponding amount of electricity generated by that steam. [EPA-HQ-OAR-2009-0491-2712.1, pp.12-13]
Upon further investigation, Linden Cogen believes that its historic reporting practices do not conform with EIA's instructions that a reporting entity should not 'report a heat rate that includes the fuel used for the production of useful thermal output. 9 Linden Cogen is in the process of submitting corrected versions of Form 860 to the EIA. The average heat rate that Linden Cogen will report for its generating units will be approximately 7965 Btu/kWh 10. This is much lower than the heat rates Linden Cogen reported in 2009 on Form 860, which ranged from 9900 Btu/kWh to 10300 Btu/kWh. While the gross heat rates previously reported by Linden Cogen are even higher than assumed by EPA in IPM (9174 Btu/kWh), we are not aware of any other source of data that might have been relied upon by EPA in assigning a heat rate of 9174 Btu/kWh to each of Linden Cogen's generating units. Nor are we aware of the source of the different, but equally erroneous heat rates that appeared in earlier versions of the NEEDS database and IPM: In the 2000 and 2003 versions, Linden Cogen's heat rate was identified as 8305.737927 Btu/kWh 11; in 2004, it was 9441.28 Btu/kWh. 12 [EPA-HQ-OAR-2009-0491-2712.1, p.13]
EPA must provide sources the opportunity to correct any inaccurate data and assumptions used in its model, before relying upon the model results to impose an arbitrary and punitive allocation on a source owner. Assuming the erroneous heat rate was derived from Linden Cogen's historic reporting of 'gross' unit heat rates on EIA Form 860, we would note that this information was submitted to a wholly separate agency to inform its ongoing analysis and projections concerning the power market. It was never intended to provide critical inputs forming the basis of proposed emission allowance allocations under an air regulatory program with significant compliance obligations. Consistent with the principles of notice and comment rulemaking and fundamental fairness, EPA must therefore provide affected facilities the opportunity to review and correct any erroneous data relied upon by IPM, before basing unit allocations on model results wholly inconsistent with a particular facility's reality. [EPA-HQ-OAR-2009-0491-2712.1, pp.13-14]
SUPPLEMENTAL COMMENTS CONCERNING IPM V.4.10 [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
The Problems Identified by Linden Cogen's October 1, 2010 Comments Concerning Reliance Upon IPM Results as the Basis for Allocating Allowances Pertain Equally to Both IPM Results Initially Released with the Proposed Transport Rule (v.3.02) and the IPM Results Released with the NODA (v.4.10) [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
While we will not restate our October 1, 2010 Comments concerning IPM in detail, IPM has wrongly projected the dispatch of Linden Cogen at only a fraction of its historical operating levels because IPM arbitrarily ignores the impact of long-term contracts on dispatch. See October 1. 2010 Comments, 5-9. Further, EPA also made several errors concerning the underlying assumptions applied to Linden Cogen within IPM that also may have contributed to IPM's erroneous projections of future dispatch for Linden Cogen. See id., 10-11. Both versions of IPM suffer from these errors. Thus, even if EPA were to rely upon the results of IPM v.4.10 released with the NODA as the basis for allocating NOx allowances in New Jersey, the resulting allocation for Linden Cogen would still represent only a small fraction of its historic emissions. See id., 6, nt. 1. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.3]
As indicated by our October 1, 2010 Comments, EPA's proposed allocations of 41 tons annual NOx and 30 tons ozone season NOx would respectively represent approximately only 10% and 19% of historic emissions, as reported during the four most recent calendar quarters. See October 1, 2010 Comments, 6. Furthermore, in comparison to average historic emissions over the past seven calendar years, EPA's proposed allocations amount to approximately only 9% and 16% of historic annual and ozone season NOx emissions, respectively. Id. Moreover, although EPA has not published a revised version of the allocation table or otherwise announced its intention to base the final allocations on the results of IPM v.4.10, the resulting projections of emissions generated by IPM v.4.10 - 45.66 tons annual NOx and 31.9 tons of ozone season NOx - would still be dramatically insufficient, although slightly higher than the results generated by IPM v.3.02. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.3]
In light of the significant shortfall in allowances that Linden Cogen would experience under either the results of either IPM v.3.02 or IPM v.4.10, Linden Cogen anticipates that it could be required to purchase allowances at a cost that could exceed $1,000,000 per year, according to estimates provided by emissions brokers. As we observed in October 1, 2010 Comments, EPA has proposed to allocate 88% of New Jersey's budgeted emissions to six coal-fired generating plants. Id., 17. Some of these facilities would receive significantly greater allocations than they had received under the Clean Air Interstate Rule ('CAIR') or than their historic emissions. Id. Thus, as a likely consequence of EPA's allocation methodology, these coal-burning facilities in New Jersey would presumably become sellers of allowances and gain a substantial subsidy, at the expense of cleaner facilities such as Linden Cogen that would become buyers of allowances. Id., 18. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.3]

 8. The supporting documentation states that 'NEEDS v.4.10 uses EIA Form 860 (2006) data as one of the primary data inputs.' Id., 4-3. The supporting documentation for EPA Base Case v.4.10 also states that, while 'EIA Form 860 (2006) and Form 767 (2005) is the starting point and largest component of the existing unit population in NEEDS v.4.10 [,] the final population of existing units is supplemented based on information from other sources, including comments from utilities, submissions to EPA's Emission Tracking System, Annual Energy Outlook, and reported capacity in Global Energy's New Entrants Database.' Id.
9. EIA Form 860, instructions for line 15.
10. The average heat rate reported for the plant's generating units may not reflect the actual heat rate of individual units or the maximum heat rates appearing in the contractual terms governing the pricing of power or reimbursement for costs related to its generation.
11.  See NEEDS Database for IPM V.2.1 and NEEDS Database for IPM 2003, available at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html.
12. See NEEDS Database for IPM 2004, available at: http://www.epa.gov/airmarket progsregs/epa-ipm/past-modeling.html.
Consolidated Edison Company of New York, Inc, (CECONY)
Recommended Changes to the NEEDS v. 4.10 Database
There are four CECONY-owned EGUs listed in the NEEDS v. 4.10 database: [See EPA-HQ-OAR-2009-0491-2653.1, p.2 for table listing the four CECONY-owned EGUs listed in the NEEDS v. 4.10 database]
In the order shown above, CECONY refers to these units as East River 2/20, East River 1/10, East River 7/70 and East River 6/60; a short description of each unit's characteristics is provided below. [See EPA-HQ-OAR-2009-0491-2653.1, pp. 2-8 for comments pertaining to units: East River 1/10 and East River 2/20, East River 6/60, and East River 7/70; See EPA-HQ-OAR-2009-0491-2653.1, pp. 3-7 for tables: Data Issue No. A-1: MW Rating of Each Plant, Data Issue No. A-2 Heat Rate, Data Issue No. A-3: Cogeneration Status, Data Issue No. A-4: Modeled Fuel, Data Issue No. A-5: NOx Combustion Controls, Data Issue No. A-6: SO2 emission rate, Data Issue. A-7: Uncontrolled NOx Base Rate, Data Issue No. A-8: Controlled NOx Base Rate, Data Issue No. A-9: Uncontrolled NOx Policy Rate, and Data Issue No. A-10: Controlled NOx Policy Rate.
Consumers Energy
We also request that the comment period for the NODA be extended from October 15, 2010 to November 30,2010, as well. [EPA-HQ-OAR-2009-0491-1890.1, p.1]
To further complicate the process, the September 1st NODA announced that EPA has placed into the docket of this rulemaking, numerous new documents and computer runs that bear directly on the proposed Transport Rule. The new information totals over 3,000 pages of documentation. The NODA provides a 45-day comment period, until October 15,2010, on the new information but states, without explanation, that the comment period on the proposed Transport Rule is not extended beyond the existing October 1, 2010 comment deadline. [EPA-HQ-OAR-2009-0491-1890.1, p.2]
The new information placed in the docket on September 1, 2010, is of central relevance to commenters' assessment of the proposed Transport Rule on such critically important matters as state emission budgets, unit allowance allocations, and state air quality 'linkages.' EPA acknowledges as much by stating in the NODA that the new information could affect the final rule by, among other things:
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i. e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. Any such changes should be evaluated by EPA. Following that, the results of EPA's evaluation should be placed into the rulemaking docket, so that affected companies can fully understand the ramifications of the NODA information. [EPA-HQ-OAR-2009-0491-1890.1,pp.2-3]
That would enable us to discuss the ramifications with our respective state environmental regulatory agencies and public service commissions. Sources and states should not be expected to comment, in a bifurcated fashion, on these extraordinarily complex, interrelated matters, and certainly should not be expected to do so on such a highly compressed schedule as is represented by EPA's current October 1 and October 15 comment deadlines. [EPA-HQ-OAR-2009-0491-1890.1, p.3]
As several other entities have pointed out, EPA is subject to neither a statutory nor court-ordered timetable to complete this rulemaking. The extended comment deadlines would provide Consumers Energy, as well as any other affected and interested organizations, a reasonable opportunity to prepare detailed, meaningful comments that may be useful to the Agency in resolving in an appropriate way the many legal, policy, and technical issues raised by the Proposed Transport Rule and, now, by the NODA as well. [EPA-HQ-OAR-2009-0491-1890.1, p.3]
On September 14, 2010, Consumers Energy submitted a request seeking the extension of the public comment period for the Transport Rule by 60 days, to November 30, 2010. We also requested that the comment period for the NODA be extended to the same date. As of this date, we have not received a response from EPA regarding either of these extension requests. [EPA-HQ-OAR-2009-0491-2837.1, p.2]
To further complicate the process, the September lst NODA announced EPA's placement in the docket of this rulemaking numerous new documents and computer runs that bear directly on the proposed Transport Rule. The new information totals over 3,000 pages of documentation. The NODA provides a 45-day comment period, until October 15, 2010, on the new information but states, without explanation, that the comment period on the proposed Transport Rule is not extended beyond the existing October I, 2010 comment deadline. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
The new information placed in the docket on September 1,2010, is of central relevance to commenters' assessments of the Proposed Transport Rule on such critically important matters as state emission budgets, unit allowance allocations, and state air quality 'linkages.' EPA acknowledges as much by stating in the NODA that the new information could affect the final rule by, among other things:
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., nonattainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
Any such changes should be evaluated by EPA, and the results of EPA's evaluation should be placed in the rulemaking docket, so that affected companies can fully understand the ramifications of the NODA information and be able to discuss the ramifications with our respective state environmental regulatory agencies and public service commissions. Sources and states should not be expected to comment in a bifurcated fashion on these extraordinarily complex, interrelated matters, and certainly should not be expected to do so, on such a highly compressed schedule as is represented by EPA's current October 1 and October 15 comment deadlines. To do so violates the very tenet of public comment by not allowing those affected by the proposed rule to provide meaningful comment for the EPA to consider in shaping a final rule. A sham comment period neither promotes the spirit, nor the letter, of the very Act that EPA claims to be enforcing by promulgating this proposed rule. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
We also requested that the comment period for the NODA be extended to the same date. On October 12, 2010, we received a response from EPA denying both of these extension requests. EPA's letter was dated October 5, 2010 and postmarked October 6, 2010. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.2]
As was the case for the proposed Transport Rule, the comment period on the NODA is arbitrarily and unreasonably short. Consumers Energy joins many others in requesting that EPA reopen the comment period, allowing a reasonable comment period and providing supporting technical documents that were not made available to the public as part of the NODA. The combination of the short comment period allotted and the lack of supporting data have made it extremely difficult for us to conduct a full review of the NODA, in order to provide meaningful comments on the NODA and how it affects the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
As both UARG and EEI point out, it is a near certainty that the new EGU information supplied by companies in their comments on the proposed Transport Rule, combined with changes to the NEEDS database and the IPM inputs identified in EPA's Transport Rule NODA, would affect, among other things, EPA's significant contribution analysis, the creation and evaluation of the cost curves, and the breakpoints selected based on the cost curves. It also is possible that the NODA, and comments received on the data contained in it, may result in changes in EPA's determinations of which states are regulated under the Transport Rule, the emission budgets to which those states will be subject, and unit-level allowance allocations supporting the final Transport Rule.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
The potential changes described above are significant. EPA did not provide a final set of information and assumptions on which the proposed Transport Rule was based at the time the proposal was issued. This error was compounded and further complicated by not providing an adequate amount of time for EEI member companies to complete an in-depth analysis of both the proposed Transport Rule and the impacts of changes caused by the NODA on individual company operations. The result of this series of errors is that EPA is placing companies, like Consumers Energy, in the position of revising plans for control projects that are currently being implemented, with associated costs in the billions of dollars. Such revisions would incur substantial cost penalties.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
UARG's comments describe, in detail, how data contained in the NODA affect key elements of EPA's proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
Consumers Energy is also aware of comments being submitted by the Midwest Ozone Group (MOG). Those comments direct EPA's attention to errors in the data characterizing existing EGUs as well as erroneous assumptions, modeling disconnects, and database errors related to the Integrated Planning Model (IPM). Specifically, MOG points out that EPA has failed to provide any Technical Support Documents (TSD) on the NODA, which are critical in understanding the new modeling platform. This is a particular concern with respect to unit allowance allocations. Without this type of information, electric generators are unable to identify, with certainty, any errors or inaccuracies, but are left to guess what these values will be under the NODA. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
 The prudent course for EPA is to retract and rethink this NODA and the proposed Transport Rule. The process requires more upfront transparency and a greater degree of involvement by the States and affected sources. EPA has neither a Court mandated nor a statutory required date for completion of this rule. Consequently, we recommend that EPA take this opportunity to make the necessary changes.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, pp.4-5]
 EPA must work with the states and affected sources to correct the numerous errors and assumption, with respect to source emissions, control plans and decommissioning plans contained within the proposed rule.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.5]
Council of Industrial Boiler Owners (CIBO)
EPA's use of the revised IPM as discussed in the NODA does not resolve the problems with the Transport Rule. As made clear in the background document for the NODA, 'Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model' (Base Case Documentation), IPM utilizes a series of 'decision variables' for 'model plants.' Model plants are 'aggregate representations of real life electric generating units.' Base Case Documentation at 2-3 and n.1. Based on IPM decision variables for model plants, EPA projects what it believes will be the heat input for each covered facility. Heat input effectively is determinative of allocations of allowances for compliance. However, IPM does not consider critical variables such as units' obligations to run based on contractual agreements (i.e., Power Purchase Agreements; whether or not a renewable energy source contracted to sell its Renewable Energy Credits; or other contractual obligations). This is a significant change from past practice of defining a boiler's heat input based on an evaluation of the past five years of data and utilization. EPA is in essences allowing IPM to determine how much a facility will run, by implementing what the model indicates is the proper allocation for any given facility. IPM, with short-sighted data, is selecting winners and losers. This problem is compounded by EPA's proposed intra-state trading only, and creates even greater difficulties for single-unit entities that cannot trade credits among units. [EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.2-3]
EPA improperly has concluded the Transport Rule will be expanded in the near future, yet its data and analytic underpinnings are not even finalized according to the NODA. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.3]
The proposal makes clear that sources gain no certainty from that rulemaking. EPA projects 2012 and 2014 projections are already outdated, as they do not account for emission reductions required under new pending or soon-to-be-issued regulations. EPA's analysis of costs for sources to comply with the Proposed Rule reflect an expectation that sources will install scrubbers, SCR or implement other similar emission control upgrades. EPA indicates that its analysis assumes only rules in place as of December 2008. Since December 2008, EPA has proposed, finalized or will propose and finalize these regulations that mandate some or all of the very same emission reduction strategies that will be required by this rule: SO2 NAAQS, NO2 NAAQS, Ozone NAAQS, Boiler MACT, CISWI, Utility MACT, PM NAAQS, CO NAAQS as well as a host of MACT and NSPS standards under the Risk and Technology Review provisions. Adding to this uncertainty for sources regarding future required controls are the requirements for greenhouse gas control, including the PSD Tailoring Rule, and upcoming NSPS for boilers. [EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.3-4]
Even regarding only the Transport Rule, the NODA itself indicates that the information is a work in progress and that EPA plans to utilize the data in v4.10 to ultimately project total and ozone period heat input for determining the amount of allowances to be allocated to a facility. Unless EPA has finalized the data and assumptions, regulated entities have no means of accurately assessing the rule's impact on their operations nor of providing meaningful comment to EPA on those impacts. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
In the broadest sense, industry needs to know what controls will be required in total so that plans and costs can be optimized. It is very hard for business to plan and budget for control needs without clarification of what reductions will ultimately be required. Open-ended piece meal regulations are inconsistent with meeting environmental objectives and planning funding and resources to accomplish those objectives in a reasonable manner. This Proposed Rule carries no semblance of certainty or the orderly administration of regulation. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
These other intervening rules also affect EPA's assumptions, yet they are unaccounted for in the model and data of the NODA. For example, EPA's planned rulemakings on NOx and utility MACT will impose additional costs and impacts on EGUs. These rules could provide different circumstances for determining whether or not a plant continues to run. In some cases, the plants that were modeled to decrease output may be the plants that are in a better position to operate under these potential new rules, but will not be able to do so because of the allocations received under the Transport Rule. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
Model plant assumptions are inflexible and lead to incorrect heat input, emission reduction assumptions, dispatch and other critical data. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
Several critical issues regarding IPM v4.10 are not clear. For example, EPA reports that it is using ETS 2007 for determining the heat rate of a unit. This is apparent from the total heat input from the CAMD data divided by the Net Output of the Facility/Unit. However, based on a preliminary review of CFB waste coal plants, the heat rate has been underestimated. In addition, plant availability and capacity also appear to have been underestimated. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
Dairyland Power Cooperative
Dairyland Power understands the NEEDS database is used by the EPA as an input to the Integrated Planning Model (IPM) v4.10, and that the EPA plans to use the modeling results from the IPM model runs in crafting a final Transport Rule regulation. If the EPA intends to go through with finalizing a regulation based on the NEEDS database and the IPM model, Dairyland Power believes it is essential that historical operating data for our units is accurately reflected in the NEEDS database. Additionally, if the EPA is going to perform modeling scenario(s) that include switching the coal type (e.g., bituminous to 100% PRB or bit.lsubbit. blend to 100% PRB) for fueling some of Dairyland Power's boilers, then it is equally essential that the NEEDS database include data that reflects the effects on unit performance associated with any coal-switch scenario the EPA is inclined to model. [EPA-HQ-OAR-2009-0491-3765.1_NODA, pp.1-2]
The EPA must not overlook the issues of boiler/fuel compatibility and fuel-related effects on boiler performance and efficiency especially if the EPA intends to create new regulatory limits on Dairyland Power units in a final Transport Rule. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.2]
I. Net Summer Dependable Capacity Does Not Correspond to Net Dependable Capacity as reported in the 2009 North American Electric Reliability Corporation Generating Available Data (GADS).
The NEEDS database column 'Capacity (MW)' is defined in the 'NEEDS v.4.10 User Guide' as 'The net summer dependable capacity (in megawatts) of the unit available for generation for sale to the grid. Net summer dependable capacity is the maximum capacity that the unit can sustain over the summer peak demand period reduced by the capacity required for station services or auxiliary equipment.' The 'Dependable Capacity (MW)' in the GADS database is reported monthly. The months of June, July and August can be averaged together to develop a net summer dependable capacity. Dairyland Power proposes the use of the 2009 GADS data for Dairyland Power's units in the NEEDS v4.l0 database for modeling the units as they are currently operated. For any scenario that switches bituminous or bituminous/subbituminous blend units to 100% PRB coal, please see the comments in section III below. The following table presents the NEEDS 'Net Summer Dependable Capacity' and the net summer dependable capacity as developed from the 2009 GADS data. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-3765.1_NODA, pp.2-3 for the table.]]
II. Heat Rate Does Not Correspond to Heat Rate as Calculated from 2009 Department of Energy EIA-923 data.
The NEEDS database column 'Heat Rate (Btu)' is defined in the 'NEEDS v.4.10 User Guide' as 'The net heat input (in Btu) required to generate 1 kilowatt hour of electricity. It is a measure of a generating unit's efficiency.' Unit net generation and heat input are contained in the Department of Energy EIA-923 report. From these two parameters, heat rate as defined in the NEEDS v.4.10 User Guide can be calculated. It is assumed that the NEEDS heat rate is an annual average since a different averaging period is not specified in the user's guide. Using the Department of Energy EIA-923 data, Dairyland Power calculated annual average heat rates for each of Dairyland Power's steam generating units. Dairyland Power proposes the use of the 2009 GADS data for unit heat rate in the NEEDS v4.10 database for modeling the units as they are currently operated. For any scenario that switches bituminous or bituminous/subbituminous blend units to 100% PRB coal please see the comments in section III below. The following table presents the NEEDS 'Heat Rate' and the net heat rate as developed from the 2009 EIA-923 data. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3765.1_NODA, p.3 for the table.]]
III. Alma Unit 4, Alma Unit 5 and Genoa (1): Loss of Capacity and Increase in Heat Rate When Burning 100% PRB Coal.
In previous comments to this docket, Dairyland Power addressed the extensive modifications that would have to be performed in order to handle and burn 100% PRB coal. In addition to combustible dust issues, it is Dairyland Power's estimate that fueling Alma Unit 4 and Alma Unit 5 with 100% PRB coal will result in an electric output capacity reduction of 37% for each unit resulting from the reduced heat input to the boiler due to the lower heating value of PRB coal. It is also estimated that unit heat rate will increase approximately 15%. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.3]
Dairyland Power's experience with fueling the Genoa (1) unit with 100% PRB coal results in an electric output capacity reduction of approximately 23% to 28% resulting from the reduced boiler heat input. The unit also experiences a heat rate penalty of approximately 13%. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4]
The following table presents the Current NEEDS capacity and heat rates for the Dairyland Power units affected by a switch to 100% PRB Coal. Dairyland Power proposes these values be used in the NEEDS database and any subsequent IPM runs that assumes a 100% PRB fuel switch as a operating/compliance scenario. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4 for the table.]]
We believe that EPA needs to do a considerable amount of work to revise the NEEDS database as it is presented in the NODA to realistically model the dispatch and emissions of the utility system with the changes USEP A has proposed in the Transport Rule. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4]
We also urge the EPA to revise the NEEDS database capacities and heat rates for Dairyland Power units consistent with the values provided in the above tables. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4]
Dominion
EPA's New Notice of Data Availability
EPA recently issued a NODA which added a significant amount of new technical information into the docket that is of central relevance to critical elements of this rulemaking that will, perhaps significantly, alter state budgets and unit allocations in a final rule. In the NODA, EPA indicates that it will base final rule budgets/allocations on a new/updated version of the IPM model as well as a revised NEEDS database. EPA has provided a 45-day comment period for the NODA which ends only 2 weeks after the October 1, 2010 date to submit comment on the proposed rule. The issuance of this NODA in the middle of the 60-day comment period EPA established for the proposed Transport Rule rulemaking that contains such a voluminous amount of new/updated information that is different, yet highly interrelated to the technical information used in development of the proposed rule has rendered evaluation and comment on this rulemaking daunting and cumbersome. In light of this NODA and the numerous assumption errors/issues noted, EPA should address/fix all assumption errors, rerun all relevant technical assessments (including reanalysis of air quality/downwind impact assessments, etc.) using the updated model, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking (SNPR). Stakeholders should not be expected to comment in such a bifurcated manner on these very complex, interrelated matters on the very compressed schedule that was put forth under EPA's current October 1st and October 15th comment deadlines. [EPA-HQ-OAR-2009-0491-2715.1, p.11]
We are still reviewing the information contained in the NODA and will submit pertinent comments specific to the NODA by October 15th. However, based on our preliminary review of the NODA, we are submitting the following corrections to the NEEDS - Version4.1 0 database: [EPA-HQ-OAR-2009-0491-2715.1, p.11]
Brayton Point (ORIS Plant Code 1619): Unit 3 is incorrectly listed as having a wet scrubber installed by 2006. As noted in Section III.1 above, this unit is scheduled to have a dry scrubber installed by 2014. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
Chesterfield Power Station (ORIS Plant Code 3797): Units 3,4 and 5 are listed as having wet scrubber installed by 2010. Unit 5 tie-in is scheduled by the end of 2011; The Unit 3 and 4 schedules have not been finalized. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
Salem Harbor (ORIS Plant Code 1626): Units 1, 2 and 3 are incorrectly listed as having activated carbon injection (ACI) technology installed in 2002. These units do not have or operate ACI controls. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
EPA's Addition of Significant New Information to the Docket That Is of Central Relevance to the Determination of State Budgets and Unit Allocations Warrants the Need for a Supplemental Proposal and Additional Time for Adequate Public Review and Comment
The NODA has added new information to the docket that is of central relevance to assessment of the Transport Rule on such critical matters such as state emission budgets, unit allowance allocations and state emission-to-downwind air quality linkages that will affect the final rule. In the NODA, EPA indicates that it will base final rule budgets/allocations on a new version of the Integrated Planning Model (IPM) as well as a revised National Electric Energy Data System (NEEDS) database, details of which it has placed into the docket. EPA has provided a 45-day comment period for the NODA which ends only 2 weeks after the October 1, 2010 deadline to submit comment on the proposed rule. The issuance of this NODA in the middle of the 60-day comment period EPA established for the proposed Transport Rule rulemaking that contains such a voluminous amount of new/updated information that is different, yet highly interrelated to the technical information used in development of the proposed rule has rendered evaluation and comment on this rulemaking daunting and cumbersome. In light of this NODA and the numerous modeling assumption errors/issues that were noted in comments previously filed on the proposed rule, EPA should address/fix all assumption errors, rerun all relevant technical assessments (including reanalysis of air quality/downwind impact assessments, etc.) using the updated model, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking (SNPR). Stakeholders should not be expected to comment in such a bifurcated manner on these very complex, interrelated matters on the very compressed schedule that was put forth under the Transport Rule proposal and this subsequent NODA. [EPA-HQ-OAR-2009-0491-3717.1_NODA, pp.1-2]
The NODA Does Not Contain All of the Pertinent Information Needed for Adequate Review and to Provide Meaningful and Comprehensive Comment
The NODA does not contain all of the pertinent data necessary to adequately assess and to comment meaningfully on the new information. Much of the information necessary to properly evaluate the nature and extent of changes that are likely to the proposed Transport Rule are not contained in the docket. While the results of 48 IPM runs (using IPM-Version 3.02) were provided in conjunction with the proposed rule, only 8 model runs (with revised Version 4.10) have been provided in the NODA. Of These, four runs related to an entirely new alternative set of model input assumptions based on the Energy Information Administration's (EIA) Annual Energy Outlook 2010 for natural gas resources, leaving only four runs associated directly to the set of 48 modeling runs used in support of the proposed Transport Ru1e. Missing in the NODA is such critical information as:
:: Cost effectiveness runs and other modeling runs including the 'TR S02 2000' IPM run and associated parsed data file that, in conjunction with the 'TR SB 2014 Limited Trading' run and parsed data file, was the basis of EPA's development of the 2014 S02 budgets and unit allocations
:: The 'TR SB 2012 Limited Trading' run and parsed file that would have reflected adjustments applied to EGU's with controls that EPA deemed 'dispatchable' that are critical to understanding of the 2012 state budgets and unit-specific allocations.
:: Comparable critical summary tables, such as 'Allocation Table - Technical Support Document for the Transport Rule - State Budgets, Unit Allocations, and Unit Emission Rate', which provided in some detail the basis of 2012 budgets and unit specific allocations including projected vs. reported data as well assumptions and adjustments made to account for operation of existing or planned/assumed pollution control equipment (controls EPA deemed 'dispatchable'). [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.2]
This information was critical to companies to complete the detailed reviews that were conducted for evaluating and providing comment on the basis for the budgets/allocations in the proposed rule. Failure to provide the detailed information on all of the pertinent data and assumptions on which EPA plans to base the final rule renders any comprehensive comment very difficult. EPA should, at a minimum, place all of this critical information into the docket and provide additional time for public comment. [EPA-HQ-OAR-2009-0491-3717.1_NODA, pp.2-3]
The Revised IPM Modeling Platform and New Information in the NODA Warrants a Re-evaluation of Both State Budgets and Unit Allocations
In the NODA, EPA indicates that the IPM policy runs (Limited Trading runs) provided include the same state-level caps that EPA modeled in the proposed Transport Rule. The state emission caps 'have not been modified to account for any changes that the new modeling might suggest' but are provided merely for 'informational purposes to allow commenters to understand the impact that changes in the modeling platform have on projected impacts of the caps'. This statement is of concern in that it suggests the possibility that EPA may consider holding the state budgets constant (as established in the proposed rule) and using the revised IPM modeling assumptions (and any unit-specific corrections applied based on comments received during the previous comment period on the proposed rule) to merely 're-distribute' allocations among individual sources in each state. We believe the effect of the new modeling will definitively result in the need to establish revised state emission budget in addition to unit -specific allocations. Although, as noted above, EPA has not provided much of the pertinent information based on the revised (Version 4.10) IPM modeling platform that is needed to fully evaluate impacts on state budgets and allocations, cursory review of the revised IPM (Version 4.10) modeling run summary reports indicate changes in projections of power demand, the projected mix of new generation capacity and emission control retrofits that would yield revised emission projections that would warrant a re-evaluation of emissions-to-air quality linkages and revised state emission budgets to the extent such budgets established in the final rule are to be based on the revised IPM modeling platform and the revised NEEDS data base.[EPA-HQ-OAR-2009-0491-3717.1_NODA, p.3]
Updated NEEDS Database
We are submitting the following corrections for Dominion owned or co-owned facilities to the NEEDS - Version 4.10 database: [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.3]
Heat Rate Corrections
:: Brayton Point Power Station (ORIS Plant Code 1619): Unit I heat rate listed as 9,110 Btu -should be 9,790 Btu; Unit 2 heat rate listed as 9,110 Btu - should be 9,870 Btu.
:: Salem Harbor Power Station (ORIS Plant Code 1626): Unit 2 heat rate listed as 10,519 Btu - should be II, I 00 Btu.
:: North Branch Power Station (ORIS Plant Code 7537): Unit IA and Unit IB heat rate listed as 11,204 Btu - should be 13,100 Btu. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.3]
:: Morgantown Energy Center (ORIS Plant Code 10743): Unit CFB I and Unit CFB2 heat rate listed as 10,331 Btu - should be 13,200 Btu. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.4]
Pollution Control Installation Corrections
:: Brayton Point Power Station (ORIS Plant Code 1619): Unit 3 is incorrectly listed as having a wet scrubber installed by 2006. This unit is scheduled to have a dry scrubber installed by the end of the 1st quarter in 2014.
:: Chesterfield Power Station (ORIS Plant Code 3797): Units 3, 4 and 5 are listed as having wet scrubber installed by 2010. Unit 5 tie-in is scheduled by the end of 2011; The Unit 3 and 4 schedules have not been finalized.
:: Salem Harbor Power Station (ORIS Plant Code 1626): Units 1, 2 and 3 are incorrectly listed as having activated carbon injection (ACI) technology installed in 2002. These units do not have or operate ACI controls. [EPA-HQ-OAR-2009-0491-3717_NODA, p.4]
Pollution Control Efficiency Corrections
:: Chesterfield Power Station (ORIS Plant Code 3797): Scrubber efficiency removal rates for Units 5 and 6 are listed at 98% - the sustained removal rates for these units are 95%.
:: Mt. Storm Power Station (ORIS Plant Code 3954): Scrubber efficiency removal rates for Units 1 and 2 are listed at 95.5% - the sustained removal rates for these units are 95%.
:: Altavista Power Station (ORIS Plant Code 10773): Scrubber efficiency removal rates listed as 95% - the sustained removal rates are 90% (dry scrubber).
:: Southampton Power Station (ORIS Plant Code 10774): Scrubber efficiency removal rates listed as 95% - the sustained removal rates are 90% (dry scrubber).
:: Brayton Point Power Station (ORIS Plant Code 1619): Units 1,2 and 3 are listed at 95% mercury removal- the sustained mercury removal rates are 85%. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.4]
Revised IPM Model-Input Assumptions
Scrubber Removal Efficiency: The revised IPM (Version.4.1 0) modeling platform assumes an increase in maximum SO2 emission removal efficiency for wet flue gas desulfurization systems (FGDs) from 95% to 98%. It is not clear whether the new 98% removal efficiency represents an assumption of continuous control efficiency. If so, this assumption is not realistic; this level of efficiency is not achievable on a continuous basis. Rather, wet scrubber removal efficiencies at these levels (98%) are generally based on vendor guarantees with spec fuels and optimal equipment condition encountered during acceptance testing. Accordingly, a 95% removal efficiency, which was used in the version of IPM on which EPA relied in developing the proposed Transport Rule, is still benchmark for sustained operation of a wet scrubber and should be retained in !PM Version 4.10. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.4]
Retrofit Assumptions for Units IPM Unit-Specific Modeling Assumptions/Inaccuracies
In comments submitted on October 1, 2010 on the proposed Transport Rule, we noted in detail numerous inaccuracies in the IPM model (Version 3.02) input assumptions specific to Dominion facilities and electric generating units that were relevant the state emission budgets and individual unit allocations in the proposed rule and provided documentation for correcting the noted discrepancies. Based on our review of the new information that is provided in the NODA, many of these inaccuracies persist and in some cases are more problematic. Although we realize it was not possible for EPA to have incorporated corrections provided in our initial set of comments prior to issuing the NODA, we are including a summary of these inaccuracies in these comments to reiterate the need for EPA to address these assumption errors, rerun all relevant technical assessments using the updated model, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking (SNPR). [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.5]
Brayton Point Unit 3): The proposed CATR assumes the installation of a wet scrubber by 2012 on Brayton Point Unit 3. In accordance with Brayton Point's Mass DEP-approved 310 CMR 7.29 Emission Control Plan a dry scrubber will be installed on Brayton Point Unit 3 for SO2 control. This dry scrubber will be equipped with a Fabric Filter (FF) baghouse for control of particulate matter emissions and will commence commercial operation in the first quarter 2014, per the Department's approval of its 310 CMR 7.29 Emission Control Plan dated December 29,2008 and Mass DEP's Proposed Conditional Approval for Brayton Point Relative to The Major Comprehensive Plan Approval for 310 CMR 7.02 Plan Approval and Emissions. Therefore, for Brayton Point Unit 3, we request the EPA modify its assumptions to include a dry scrubber with a commercial operation date of first quarter 2014, consistent with Mass DEP's Emission Control Plan approval dated December 30, 2008, and modify the unit and state budgets accordingly. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.5]
Salem Harbor Units 1, 2 and 3: In the proposed rule, EPA did not allocate NOx allowances for Units 1 and 2 apparently due to an erroneous adjustment made to projected 2012 NOx emissions to account for annual operation of SNCR's. In addition, EPA assumed a scrubber would be installed on Unit 3 by 2012 resulting in a significant shortfall of S02 allocations. The new IPM Version 4.10 runs are more problematic in that the model predicts that all 3 coal units do not operate in the 2012 base case (no predicted fuel throughputs by the model). There is no explanation provided for these changes. Although EPA has not provided any of the detailed resultant unit-specific allocations (as it did for the initial IPM-Version 3.02 runs used in the proposal), one could assume that use of the Version 4.10 modeling assumption would result in no allocated allowances for both S02 and NOx for these units in 2012. Although the model does show the units running (with a scrubber on Unit 3) in the 2014 'Limited Trading' policy run, it is not clear what relevance this would have to allocations beginning in 2014 (and beyond) since NOx allowances for all states and S02 allowances for Group 2 states (Massachusetts) are based on the 2012 modeling projections and are applicable for 2012 and all years beyond. (Group 2 states are not subject to the additional S02 budget reductions and revised allocations imposed in the Group 1 states beginning in 2014). There is no explanation provided for the discrepancy between the 2012 base case run (assumes units do not operate) and the 2014 policy run (units assumed to operate). As noted in our previous comments, Salem Harbor Units 1 and 2 are committed operationally and commercially to provide capacity at least through May 31, 2012 in the region's Forward Capacity Market (FCM) managed by New England's Independent System Operator (ISO-NE). Although static-delist bids were accepted by ISO-NE for each of these units in Forward Capacity Auctions (FCAs) 3 and 4, the acceptance of these bids by ISO-NE does not preclude these supply resources from continuing to operate for regional energy and ancillary services support and thus require both NOx and S02 allowances under the CATR. Unit 3 is committed operationally and commercially to run at least through May 31, 2014 (and very possibly may be required longer) in accordance with ISO-NE's determination that the unit - together with Salem Harbor Unit 4 - is needed to support system reliability in the Boston Import Area. In addition, the model assumes a scrubber on Unit 3 by 2014. We have not planned to install a scrubber on this unit. However, Salem Harbor will continue to achieve S02 emission reductions to comply with 310 CMR 7.29 in accordance with the June 2003 Administrative Consent Order (ACO) Number ACO-NE-03-7001 and subsequent May 2005 amendment (AACO).[EPA-HQ-OAR-2009-0491-3717.1_NODA, p.6]
Brayton Point Unit 4 (Oil) and Salem Harbor Unit 4 (Oil): As in the previous version of IPM, the revised modeling runs assume that Brayton Point Unit 4 and Salem Harbor Unit 4 will not continue to run past December 31, 2011 (model predicts no heat input capacity for these units). While these units typically have low capacity factors, we fully expect to operate them in the future, as demonstrated by the capacity supply commitments from the FCM 2, 3 and 4 auction. Moreover, Salem Harbor Unit 4 is needed to support Boston Import Area reliability at least through May 31, 2014 in accordance with ISO-NE's determinations in the FCM 3 and 4 auctions. Therefore, for Brayton Point and Salem Harbor Units 4, we request that EPA modify
Brayton Point Unit 4 (Oil) and Salem Harbor Unit 4 (Oil): As in the previous version of IPM, the revised modeling runs assume that Brayton Point Unit 4 and Salem Harbor Unit 4 will not continue to run past December 31, 2011 (model predicts no heat input capacity for these units). While these units typically have low capacity factors, we fully expect to operate them in the future, as demonstrated by the capacity supply commitments from the FCM 2, 3 and 4 auction. Moreover, Salem Harbor Unit 4 is needed to support Boston Import Area reliability at least through May 31, 2014 in accordance with ISO-NE's determinations in the FCM 3 and 4 auctions. Therefore, for Brayton Point and Salem Harbor Units 4, we request that EPA modify its assumptions to include continued operation of both units consistent with IS0-NE market rules and modify the unit and state budgets accordingly. [EPA-HQ-OAR-2009-0491-3717.1_NODA, pp.6-7]
Possum Point Unit 5 and Yorktown Unit 3 Oil-Fired Units: The revised IPM modeling projections show no fuel throughput in the 2012 base case run or the 2014 policy run. Although annual capacity factors have been low in recent years, these units are called upon to operate under certain conditions and are expected to continue to do so in the future. As noted in our previous comments, Dominion Virginia Power is a member of the PJM RTO and is subject to its reliability requirements and market rules. The RPM capacity market is a three-year forward market that acquires capacity to meet load plus reserve requirements. Possum Point 5 and Yorktown 3 are currently committed through May 2014 and it is our intent to continue committing these units into RPM as a means to meet our capacity requirement. Both units have run for economic and reliability reasons and there is no basis to conclude that pattern will change. Accordingly, EPA should allocate a reasonable number of allowances to these units based on historical data (at a minimum, averaged over several years).[EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Morgantown Energy Center: In our comments for the proposed rule, we indicated that EPA may have assumed that this facility is exempt from the CATR requirements under the proposed provisions of the rule that exempt certain cogeneration units and provided information (with supporting documentation) explaining why we believe the facility does not qualify for the exemption. We could find no information concerning this facility in the detailed parsed files provided for the revised IPM-Version 4.10 base case 2012 and 2014 Limited Trading policy runs. Accordingly, we reiterate our previous comments that this facility should be treated as a CA TR -affected facility and should be allocated appropriate S02 and NOx allowances. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Bremo Units 3 and 4: The IPM-Version 4.10 2014 policy run predicts scrubbers on these units by 2014. There are no specific requirements or current plans to install scrubbers on these units. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Additional EPA Updates Concerning Pollution Controls
EPA's document entitled 'Planned Updates to IPM v.4.10' lists a 'planned future revision' with respect to particulate matter (PM) controls for Dominion's State Line Unit 4 coal-fired boiler. Section III - Table 1 indicates that current assumptions for PM controls, which consist of a cold-side electrostatic precipitator (ESPC), will be revised to reflect the installation of hot-side ESP (ESPH) and a baghouse. The Company has no current plans to convert to an ESPH or to install a baghouse. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Coal Price Assumptions Used in IPM [EPA-HQ-OAR-2009-0491-3771.1_NODA, p.1]
The minemouth Appalachia coal prices identified in the IPM v4.10 Runs and Parsed Files appear to be between 20% and 30% low relative to the current market and between 5% and 10% low relative to the Appalachia coal prices identified in EIA 2010 Annual Energy Outlook. The use of such low coal price projections within the IPM framework will lessen the adverse financial impact on coal generating units resulting from the Transport Rule. Consequently, the IPM runs will result in a lower level of projected coal unit retirements which will in turn mask potential future reliability issues. To address this concern, Dominion recommends EPA perform an IPM sensitivity analysis that reflects increased coal prices. The results should be analyzed to assess the magnitude of coal unit retirements and also the level of new generation necessary to maintain adequate reserve margins under such a scenario. [EPA-HQ-OAR-2009-0491-3771.1_NODA, p.1]
DTE Energy
EPA has not provided adequate information for stakeholders to provide meaningful analysis and comments on the NODA and its impact on the Proposed CATR. DTE does not have access to relevant information to determine appropriate unit specific allocations, or even Michigan's budget, as a result of EPA's revised Base Case v4.10. EPA has requested electric generating companies to provide detailed comments correcting any inaccurate data or incorrect assumptions made with respect to specific units. The lack of information, completely identified in the comments of UARG, prevents DTE from the ability to evaluate the accuracy of EPA's assumptions with respect to its individual units and provide meaningful comments. [EPA-HQ-OAR-2009-0491-3714.1_NODA, p.2]
EPA's decision to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database and updated IPM platform while leaving state budgets based on unrevised data and IPM platform used in the Proposed CATR is illogical and arbitrary. The very substantial changes in EPA's projections for demand for power, the projected mix of new generation capacity, and projected pollution control retrofits suggest that it would be reasonable to expect significant changes in 2014 SO2 budgets for group 1 states if those budgets are based on the revised versions of NEEDS and IPM. [EPA-HQ-OAR-2009-0491-3714.1_NODA, p.2-3]
DTE Energy Services (DTEES)
DTEES would also like to correct several errors in the National Electric Energy Data Systems (NEEDS) v.4.10 database for EJ Stoneman.
The online date is incorrect. The database states 2009 yet the facility has yet to reach full load operation in order to be considered 'online' and delivering electricity reliably under the power purchase agreement. The facility did not fire any woody biomass until July 28, 2010 and construction and commissioning is still ongoing as of October 1st, 2010. ;
The SO2 permit rate is 3.17 lbs/mmBtu. ;
Uncontrolled NOx base rate is 0.33 lbs/mmBtu (also not sure if this is applicable since the units are covered by a NOx control policy, for ex BACT) ;
Firing is not Wall, this was the configuration for coal firing. Woody biomass firing is with vibrating hydrograte Stoker. ;
NOx Post-CombControl should be SNCR, NOx Comb Control should be over-fired air;
Using a Mode 2 NOx emission rate is inappropriate since the unit does not have a mercury emission limit nor will it. Additionally, the Mode 2 NOx emission rate is inaccurate in that it should be 0.2 lbs/mmBtu. ;
Mode 3 NOx emission rate is inappropriate since the units are not covered by a seasonal NOx policy, the Mode 3 NOx emission rate is inaccurate in that it should be 0.2 lbs/mmBtu. ;
The Mode 4 NOx Rate should be 0.2 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-2699.1, pp.4-5] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.4]
Duke Energy
It seems certain that the significant differences between the data on which EPA based the Proposed Transport Rule and the data EPA released pursuant to the NODA, along with additional data updates EPA has indicated it plans to make will have significant impacts on all aspects of the rule, including state budgets and unit level allowance allocations. Therefore, EPA should incorporate the NODA data or whatever other data EPA may now deem most appropriate while addressing the many comments it has received to date, rerun its analysis and issue a new proposal for public comment before issuing a final rule. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
Changes to the NEEDS v4.10 Database. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
Assumed Scrubber Efficiencies for Some Duke Energy Units in the NEEDS v4.10 Database are Inappropriate for Purposes of Modeling and Should Be Changed. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
Cayuga (ORIS PL 1001) Unit 1. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
The NEEDS v4.10 database indicates 98% SO2 removal efficiency for the existing FGD systems ('scrubbers') at Duke Energy's Cayuga (ORISPL 1001) Unit 1. This unit is designed for 97% removal and have performed at that level on a regular basis but at lower than design sulfur coal. Recent performance has continued at design level primarily due to reduced load demand which has masked the affects of normal wear on equipment such as the recirculation pumps. The limestone that is readily available to this unit is borderline in CaCO3 content which makes it difficult to achieve design performance and meet the required gypsum quality for aftermarket sales. One way to increase the SO2 removal is to increase the absorber pH. But one of the consequences of raising the pH is a reduction in gypsum quality. This FGD system and the wastewater treatment system are not designed for the addition of performance enhancing additives such as Dibasic Acid. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.2-3]
Duke Energy projects that this unit at best can achieve a 97% removal consistently over the full range of coal quality expected. To achieve 98% SO2 removal would require significant capital modification to the system that would exceed the $2,000 per ton cost breakpoint, and would produce uncertain results. For these reasons, EPA should assume a removal efficiency of 97% for this unit. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.3]
W H Zimmer (ORISPL 6019) Unit 1. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.3]
The NEEDS v4.10 database incorrectly shows 98% removal efficiency for the existing Zimmer Unit 1 FGD system ("scrubber"). This unit cannot average 98% removal and EPA should use a lower assumed removal percentage for setting the Ohio state SO2 budgets and allocating SO2 allowances. Duke Energy strongly recommends a removal efficiency of no greater than 95%. The Zimmer Station Unit 1 scrubber was designed in the late 1980's. As an NSPS unit, it was permitted and constructed at that time to meet a 91% removal requirement. Its scrubber tower size and configuration was designed to use a magnesium enhanced lime process which places significant restrictions on its performance. This unit has a much smaller tower height compared to limestone scrubbers and is limited to a much lower liquid to gas ratio. These physical limitations coupled with the process's chemical reaction kinetics make 98% removal efficiency unattainable. If Zimmer's scrubber were intended to achieve 98% removal, it would have been designed and constructed very differently. These changes cannot be retrofitted into the existing unit. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.3-4]
Duke Energy projects that this unit at best can achieve a 95% removal, but even this level of performance has not been demonstrated on a sustained basis. Achieving even this level exceeds the scrubber's original design envelope and operating outside the air permit's specification to operate with installed spare equipment. As another example, to prevent pluggage due to scaling, the mist eliminators in each module must undergo regular cleaning. This requires that one of the six modules is almost always out of service an any given time. This necessity was reflected in the original facility air permit. For these reasons, Duke Energy therefore recommends that EPA assume a removal efficiency of no more than 95% for Zimmer's scrubber. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.4]
Cayuga (ORISPL 1001) Unit 2, Gibson (ORISPL 6113) Units 1, 2, and 3, and Miami Fort (ORISPL 2832) Units 7 and 8. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.4]
The NEEDS v4.10 database indicates that Cayuga (ORISPL 1001) Unit 2, Gibson (ORISPL 6113) Units 1, 2, and 3, and Miami Fort (ORISPL 2832) Units 7 and 8 are dispatchable scrubbers. It is not clear why any of these scrubbers are shown as dispatchable. Given that they are shown as dispatchable, there is no scrubber efficiency shown for these units. The FGD systems for each of these units are designed for 97% removal and have performed at that level on a regular basis but at lower than design sulfur coal. Recent performance has continued at design levels primarily due to reduced load demand which has masked the affects of normal wear on equipment such as the recirculation pumps. The limestone that is readily available to these units is borderline in CaCO3 content which makes it difficult to achieve design performance and meet the required gypsum quality for aftermarket sales. One way to increase the SO2 removal is to increase the absorber pH. But one of the consequences of raising the pH is a reduction in gypsum quality. These FGD systems and the wastewater treatment systems are not designed for the addition of performance enhancing additives such as Dibasic Acid. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.4-5]
Duke Energy projects that these units at best can achieve a 97% removal consistently over the full range of coal quality expected. To achieve 98% SO2 removal would require significant capital modification to the system that would exceed the $2000 per ton cost breakpoint, and would produce uncertain results. For these reasons, Duke Energy therefore recommends that EPA assume a removal efficiency of 97% for each of the units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.5]
Marshall (ORISPL 2727) Units 1, 2, 3, and 4, Belews Creek (ORISPL 8042) Units 1 and 2, and G G Allen (ORISPL 2718) Units 1, 2, 3, 4, and 5. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.5]
The NEEDS v4.10 database indicates 98% SO2 removal efficiency for the existing FGD systems ("scrubbers") at Duke Energy's Marshall (ORISPL 2727) Units 1, 2, 3 and 4, Belews Creek (ORISPL 8042) Units 1 and 2, G G Allen (ORISPL 2718) Units 1, 2, 3, 4 and 5 in North Carolina. None of these scrubbers are capable of averaging 98% SO2 removal. EPA should therefore use a lower average removal efficiency percentage for these units for setting the North Carolina state SO2 budgets and allocating SO2 allowances. Duke Energy strongly recommends a removal efficiency of 95%.  [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.5]
The Marshall, Belews Creek and Allen scrubbers were each designed to meet the North Carolina Clean Smokestack Act annual SO2 emission caps. Although there was no specific SO2 removal efficiency requirement specified in the state legislation, the FGD systems were designed to achieve 95% SO2 removal. Due to the structure of the state program as a system-level cap, the scrubber designs did not include the installation of spare Absorber Recycle Pumps. Demonstrated performance testing has verified that each scrubber is currently achieving 95% SO2 removal performance. However, recycle pump reliability has not met expectations and has placed the 95% SO2 removal at risk on a long-term performance basis. Certainly, the scrubbers are not capable of averaging 98% SO2 removal. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.5-6]
While certain performance enhancing organic acids, like Dibasic Acid ("DBA") have been tested and utilized in the utility industry to enhance FGD performance, the number of sources of DBA has diminished significantly and currently the remaining sources are oversubscribed (no availability). Looking at substitutes, the projections are that suitable substitutes will also be oversubscribed and will have limited availability. In addition, the currently installed DBA storage and handling system at each plant may be incompatible with substitutes and will likely require significant modification to installed equipment. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.6]
Duke Energy projects that each of these FGD systems at best can achieve a 95% continuous average removal efficiency but with significant uncertainty. Achieving even this performance level exceeds the scrubber's capability on a long term basis without installed spare equipment. To achieve higher SO2 removal would require significant capital investment with uncertain results and the same spare equipment limitations, and at a cost likely to exceed the $2000 per ton cost breakpoint. For these reasons, Duke Energy recommends that EPA assign and model the Marshall, Belews Creek and Allen scrubbers at 95% SO2 removal efficiency. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.6]
The NEEDS v4.10 Database Incorrectly Indicates That Some Units Are Currently Capable of Burning Subbituminous Coal [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.7]
The NEEDS v4.10 database incorrectly shows a number of Duke Energy units as being capable of burning subbituminous coal. They include R Gallagher (ORISPL 1008) units 1-4, Miami Fort (ORISPL 2832) unit 6, and Walter C Beckjord (ORISPL 2830) units 1-6. In its Transport Rule proposal, EPA states that its "...analysis does not allow a unit designed for bituminous coal to switch to (very low sulfur) subbituminous coal unless the unit has demonstrated that capability in the past. EPA assumes units with that capability have already made any investments needed to handle a switch to subbituminous coals. EPA therefore assumes that any modeled coal switching from bituminous to subbituminous has no cost or schedule impact." EPA has provided no information about what in its view constitutes a demonstration of the capability to burn subbituminous coal. In cases where IPM has modeled a 100% fuel switch to subbituminous coal, it seems reasonable that having demonstrated the capability would mean that the unit IPM has switched has actually operated on 100% subbituminous coal in the past. Certainly units that have never burned subbituminous coal in any quantity would not be considered to have demonstrated the capability to burn subbituminous coal. Yet the NEEDS v4.10 database shows the above identified units as capable of burning subbituminous coal, and the TR_SB_Limited Trading_2014 parsed file that was added to the docked as part of the NODA shows each of these units burning 100% subbituminous coal where none of the units have never burned any amount of subbituminous coal in the past, not even for a test burn. This is clearly an error that should be corrected. None of these units are capable of burning subbituminous coals. No capital investment has been made that would allow these units to safely handle and burn this fuel type, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. In addition to the fact that none of these units have ever burned any subbituminous coal, Duke Energy has estimated the cost of fuel switching these units to be far in excess of EPA's $2,000 per ton cost breakpoint for SO2. It is therefore not appropriate for IPM to model any of these units as being capable of burning subbituminous coal. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.7-8]
The NEEDS v4.10 database also shows that Duke Energy's Miami Fort (ORISPL 2832) Units 7 and 8 are capable of burning subbituminous coal. These units are only capable of burning up to a 20% blend of subbituminous coal. Significant capital investment would be required to allow the units to safely handle and burn this fuel type in blends higher than 20%, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. However, Miami Fort Station does not have a coal handling system that would allow for the controlled blending of bituminous and subbituminous coals, and these units cannot burn straight subbituminous coal (such as with alternating the fuel types). Therefore, EPA must include the cost of an on-site coal blending system (approximately $55 million for the two units), or increase the cost of the delivered fuel to account for off-site blending cost premiums (approximately $10 to $14 per ton of blended coal from terminals on the Ohio River) in any consideration of subbituminous coal at these units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.7-8]
There Are Affected Units Missing From the NEEDS v4.10 Database. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.8]
The Edwardsport (ORISPL 1004) Units 7-1, 7-2, and 8-1 are each existing Proposed Transport Rule NOx Annual, Ozone Season, and SO2 Group 1 units based on the applicability criteria of §97.404, §97.504, and §97.604 of the Proposed Transport Rule. Each of these units reports emissions data to EPA under the Acid Rain Program and the CAIR SO2 and NOx programs. None of these units, however, appear in the NEEDS v4.10 data base and are therefore not included in the IPM modeling. EPA states in its Proposed Transport Rule State Budget, Unit Allocations, and Unit Emissions Rates Technical Support Document that "IPM is a representation of all units which are capable of supplying electricity to the US electric grid..." Each of these units meets this criterion for inclusion in IPM. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.8-9]
It appears that none of these units were included in the inventory of units used by EPA to establish the Indiana SO2 and NOx budgets, but per EPA's stated methodology for establishing state budgets, they should have been included. In addition, per EPA's stated methodology for allocating allowances to individual units, each of these units should have received both SO2 and NOx allowance allocations, but EPA has proposed neither SO2 nor NOx allocations for any of the units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
Duke Energy requests that EPA include each of these units in the determination of the Indiana SO2 and NOx budgets, and allocate allowances to each unit appropriately. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
Incorrect Particulate Controls Identified in NEEDS v4.10. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
The NEEDS v4.10 database shows the R Gallagher (ORISPL 1008) Units 1-4 with cold side electrostatic precipitators ("ESPC"). Each of these units is equipped with a baghouse. Each ESPC has been retired and removed. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
NEEDS v4.10 Indicates Selective Noncatalytic Reduction ("SNCR") Technology Where the Technology No Longer Exists. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
The NEEDS v4.10 database indicates that Duke Energy's Miami Fort (ORISPL 2832) Unit 6 has SNCR. The SNCR has been completely removed from this unit (the EPA website indicates that the SNCR was retired on September 30, 2008, but it was physically removed in the spring of 2006). As a result, when EPA updates the NOx emission rates to 2009 rates, it should not apply a 35% reduction factor to this unit's emission rates to account for SNCR operation, which means the Controlled NOx Base Rate and the Controlled NOx Policy Rates for this unit should be the same as the Uncontrolled NOx Base Rate and Uncontrolled NOx Policy Rate. In the NEEDS v4.10 data base the Controlled NOx Base Rate and the Controlled NOx Policy Rate for this unit are currently shown 35% lower than the Uncontrolled NOx Base Rate and Uncontrolled NOx Policy Rate. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.9-10]
There are Errors in the IPM Modeling That Need to Be Corrected. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.11]
IPM Is Modeling Some Duke Energy Combustion Turbines as Oil-Fired Units That Should Be Modeled As Natural Gas Units [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.11]
The NEEDS v4.10 database shows Duke Energy's Rockingham (ORISPL 55116) combustion turbines Units 1-5 as natural gas and distillate oil-fired units. While these units are capable of burning both fuels, their primary fuel is natural gas. Both the TR_Base_Case_2012 and TR_SB_Limited Trading_2014 parsed output files included as part of the NODA, however, indicate that IPM is selecting oil as the fuel type for these units and as a result, IPM does not operate any of the units. This is incorrect. These units should all be modeled as natural gas-fired units. IPM is selecting natural gas as the fuel type for Duke Energy's other North Carolina combustion turbines, and for all but a few other combustion turbines in the state so it makes no sense that IPM should select oil as the fuel type for any of the Rockingham units. These units would not be operated on oil while Duke Energy's other combustion turbines in North Carolina are operating on natural gas. Duke Energy requests that EPA correct this error and ensure that IPM models these 5 units as natural gas-fired units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.10]
IPM Has Inappropriately Fuel Switched Duke Energy Units to a Lower Sulfur Bituminous Coal [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.11]
The ParsedFile TR_SB_Limited Trading_2014 that is part of the NODA shows that IPM has switched Duke Energy's Wabash River (ORISPL 1010) units 2, 3, 4, and 5 to about a 0.7 lb/mmBtu SO2 bituminous coal. However, EPA has not provided any additional detail about the quality and nature of this proposed fuel, including full proximate and/or ultimate analysis or the modeled source region. The constituents of coal can vary dramatically, even within the same seam and general sulfur grade. It is difficult for Duke Energy to assess the potential impact of this fuel on the units without knowing this additional detail. This would include ash content and moisture content, as well as fuel combustion characteristics such as grindability, slagging and fouling indices, and volatility. Knowing these details is critical to making an assessment of whether the unit can manage this fuel. Wabash River Units 2, 3, 4, and 5 have ball mills, which are especially susceptible to changes in coal properties. Higher ash, higher moisture, and/or lower grindability characteristics, which are typical in some combination for most lower sulfur coals (whether bituminous or subbituminous), can result in mill skidding and reduced mill fineness. This usually results in increased boiler slagging and fouling; pluggage; higher NOx and CO emissions; lower unit efficiency; higher opacity; and therefore reduced unit availability and capacity. It can also result in mill explosions, which are a significant safety hazard, and require expensive fire protection and suppression system upgrades (again, even for bituminous coals); and in conjunction with ash resistivity impacts, reductions in precipitator performance requiring precipitator conditioning systems and/or expensive precipitator upgrades or replacements, as the precipitators on these specific units are very small (only 130 SCA, with rigid discharge electrodes and 11 inch plate spacing), and were originally designed for 6 to 7 lb/mmBtu SO2 fuels. These units have not been able to burn coals with less than 2.8 lb/mmBtu SO2 without suffering constant opacity exceedances. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.11-12]
Further, IPM has specified the same coal grade for Wabash River Unit 6 (approximately 0.7 lb/mmBtu SO2). The current Wabash River unit 6 precipitator is an Environmental Elements design and was installed in 1993. It has a Specific Collection Area (SCA) of 281 and was designed to burn medium sulfur coal (2.5  -  3.5 lb/mmBtu SO2). It consists of two (2) casings arranged in a parallel configuration. Each precipitator casing has four (4) fields with fifty foot (50') tall collecting plates, and eight (8) chambers with one hundred fifty eight (158) gas passages spaced at sixteen inches (16"). The precipitator is powered by eight (8) 70kV, 750 mA, and eight (8) 70kV, 1000mA transformer-rectifier (T/R) sets. The precipitator is a rigid discharge electrode (RDE) design and treats 1,310,398 ACFM of flue gas at 291F. Design gas velocity is 4.31 feet per second. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.12-13]
This unit typically burns a 1.67 lb/mmBtu SO2 or higher coal on a daily basis with an average opacity of 10% or less. In the past a lower sulfur coal (1.2 lb/mmBtu SO2 range) was tried and the unit began to experience high opacity (20% - 30%). An even lower sulfur coal (0.8 lb/mmBtu SO2) was tried with no success. The unit experienced constant emissions excursions. In order to burn a 0.7 lb/mmBtu SO2 low sulfur coal, Wabash River Unit 6 would need to install a SO3 flue gas conditioning system. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.13]
Due to the limited information provided, and the limited time allotted for comments, Duke Energy cannot reasonably research, engineer, and develop a capital cost estimate for this grouping of projects that would be instructive for EPA to consider in its economic assessment. Duke Energy can therefore only recommend, due to the configuration of these specific units and the recognized impact that coals of this general characteristic can have, that these units are not capable of burning the fuel selected by IPM (or equivalently, that given the proper time for project development, cost estimation, and assessment of the impacts on unit availability and capacity, that this option has a high likelihood of exceeding the $2000/ton cost breakpoint for SO2). [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.13]
Duke Energy requests that EPA model no less than a 1.67 lb/mmBtu SO2 bituminous coal for Wabash River Units 2 through 6. Coal of this general sulfur grade represent a vastly larger market share than the ~0.7 lb/mmBtu SO2 coal, offer wider variability in constituents and combustion characteristics (thereby making finding a suitable fuel more likely), and may even represent a mix of higher and lower sulfur fuels again optimizing sourcing options. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.13-14]
In addition, Wabash River Station has a common coal handling system for all of the units that would require a capital investment to separate the system to allow Unit 6 to manage a vastly different fuel from Units 2 through 5 which would likely cost significantly more than $2000 per ton. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
Lastly, the ability to specify a suitable fuel with a sulfur content in the 0.7 lb/mmBtu SO2 range in the market that has the requisite composition and characteristics to minimize the operational problems on these units may significantly limit the volume of fuel available, thereby resulting in higher coal costs than what IPM may be modeling (and thus affecting the economic assessment of this fuel choice relative to the $2000/ton cost breakpoint for SO2). Otherwise, a considerable capital investment would be required, including investments in the precipitators and mills, again affecting the economic assessment of this option. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
Recommended Updates to NOx Emission Rates in NEEDS v4.10 Data Base. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
EPA Should Apply an Annual and Ozone Season Floor NOx Emission Rate of 0.06 lb/mmBtu to both New and Existing SCRs. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]