Document ID: EPA-HQ-OAR-2009-0491-4529
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2011-07-12T04:00Z

Docket Number EPA - HQ - OAR - 2009 - 0491
                                       
Response to Comments on the Proposed Transport Rule: Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone
                         (75 FR 45210; August 2, 2010)
                                       
                                       
                                  Transport Rule
                             Engineering Feasibility
                               Response to Comments
                                       
                                       
                                       
                                       
                                       
                                       
                     U.S. Environmental Protection Agency
                          Office of Air and Radiation
                                   July 2011
Contents

Introduction	3
Implementation Issues	4
Emission Control Capabilities	13
Implementation Costs	14
Switching from Lignite to Subbituminous	15

Introduction

This document responds to comments on the proposed Transport Rule and supplements the Transport Rule Primary Response to Comments (available in the docket). This document provides responses to significant public comments on engineering feasibility as received in response to the United States Environmental Protection Agency's Notice of Proposed Rulemaking (NPR): Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Interstate Air Quality Rule), issued August 2, 2010.       
An extensive general discussion of engineering feasibility is provided in preamble section VII.C.2, Compliance and Deployment of Pollution Control Technologies. It addresses many of the major aspects of the engineering feasibility of implementing the flexible range of technical options available for compliance with the Transport Rule by its compliance deadlines of January 1, 2012 and January 1, 2014. This document provides responses to additional engineering feasibility concerns that were repeated by multiple commenters. 
The full text of all comments to which these responses apply are included in the Transport Rule Primary Response to Comments, section V.C.2, Reductions as Expeditiously as Practicable/Feasibility of the 2012 and 2014 Compliance Deadlines (available in the docket). Certain related comments, including those supporting the rule's engineering feasibility, are separately addressed in the Transport Rule Primary Response to Comments, section V.C.2.
Responses provided in this document are organized under the following major subject headings, each representing broad general areas of concern to multiple commenters:
   * Implementation Issues 
   * Emission Control Capabilities
   * Implementation Costs 
   * Switching from Lignite to Subbituminous
   
Responses are presented as individual paragraphs under these headings, addressing more specific areas of concern as identified by each paragraph subheading. 
Implementation Issues 
Request to Defer Implementation for Compliance
   After careful consideration of public comments and the evidence on record for EGU emission reduction feasibility, EPA did not find a reasonable technical basis for altering the Transport Rule compliance deadlines of 2012 and 2014 as originally proposed.  See preamble section VII.C regarding EPA's rationale for the compliance schedule.  
Owner's Decisions & Options
   As part of the court's remand, the CAIR programs have remained in place temporarily until superseded by EPA's promulgation of the Transport Rule.  While some utilities opted to temporarily slow, delay or suspend retrofit activities in the wake of the court's judgment and pending the promulgation of the replacement rule, these actions do not constitute a sufficient basis for determining that such sources are incapable of meeting the replacement rule's compliance dates.  The owner is ultimately responsible for assuring adequate and timely performance of a retrofit installation by utilizing competitive supplier selection to award a contract.  Moreover, the Transport Rule is inherently flexible  -  it allows unit owners multiple options to attain compliance deadlines;  namely, unit owners may choose to maximize performance of existing pollution controls, shift power generation to cleaner units, expedite retrofit work where necessary (utilize multi-shift schedule or extended overtime), increase use of cleaner fuels, and/or purchase allowances to cover emissions. 
Conflicts with a Utility's Long Term Plans
   The EPA believes promulgation of the final Transport Rule provides important regulatory certainty which will allow utilities to improve planning efforts and, if necessary, amend long-range strategic plans as they have successfully done in response to past regulations.   EPA is not responsible for aligning its regulatory actions (which are authorized by statute) to any corporation's pre-existing planning, whether or not such planning accurately anticipates specific regulations.  EPA conducts a notice-and-comment rulemaking period giving the public and affected entities advanced notice of pending regulations.  The opportunity for input before finalization allows additional time for affected sources to adjust their long-range planning accordingly.
Municipality Impacts and Challenges
   EPA analyzed and considered the impacts of the Transport Rule on municipal EGUs.  For a discussion on the rule's impact regarding municipalities, see RIA chapter 9.
Complete Detailed Engineering Required for Initiating Work 
   Complete detailed engineering is not required for making an award; rather, an award requires conceptual engineering to size major equipment, determine process flows, identify scope, establish permit requirements, and estimate total installed cost.  At its conclusion, order placement for long lead items and permit submission can occur.  Detailed engineering is required for construction and installation activities. 
   
   The Transport Rule generally sustains an already-present economic incentive for pollution control retrofit planning originally imposed by the Clean Air Interstate Rule.  Many retrofit planning activities launched under CAIR, including fleet assessment, conceptual studies, cost estimates, process flows, material balances, drafting permit applications, and aligning prime contractors and sub-contractors, should have been completed and retained by many utilities.  Some utilities may have decided to temporarily postpone further deployment in response to the remand of CAIR (for example, Clifty Creek and Kyger Creek, but upon promulgation of the Transport Rule, work can resume efficiently with installation. As a result, the EPA anticipates that units originally affected under CAIR are in a position to issue contract awards efficiently and in a timely manner for desired retrofits to make emission reductions under the Transport Rule programs.  
Negotiating Contracts, Competitive Bid Evaluation  -  More Time Required for Compliance
   EPA believes that in response to CAIR and subsequently to the proposed Transport Rule, utilities were well positioned to solicit and evaluate retrofit project bids as part of their advance planning efforts that have been visibly underway from many companies.  This preparation would allow efficient decisions to award contracts upon final Transport Rule promulgation, consistent with the compliance deadlines which industry has been able to anticipate since the Transport Rule's original proposal.  As EPA explained in the proposed Transport Rule, the Court's remand of CAIR in 2008 explicitly rejected that rule's 2015 deadline as failing to respect Clean Air Act attainment deadlines for downwind areas, and that a replacement rule would need to respect these attainment deadlines.  As a consequence of the Court's ruling on CAIR, EPA believes any reasonable observer could have anticipated as early as 2008 that EPA's replacement rule would need to consider necessary emission reductions prior to 2015; therefore, it is reasonable for EPA to expect that utilities would have commenced advanced planning efforts for potential cost-effective retrofits, including contract negotiations and bid evaluations, in advance of final promulgation of the Transport Rule. 
Financing / Investment Difficulties
   EPA has not observed financing obstacles for pollution control retrofits under its previous trading programs.  The EPA includes publicly-reviewed financial assumptions regarding pollution control investments in its IPM modeling of the power sector which indicates that the projected retrofits are economically viable in response to the final Transport Rule's state budgets.  The Transport Rule's market-based trading programs create "bankable" value in each ton of emission reductions, thereby supporting financing in pollution control retrofits.  Furthermore, the financial industry views utilities with large customer bases as less risky to finance due to the consistent, ample revenue stream.  As noted in section VII.C.2 of the preamble, the projected cost-effective retrofits under the Transport Rule all occur at capacity owned by such large utilities.  To reduce financing risk, utilities have the option to award "fixed price" contracts.  Considering the past successes of the pollution control industry regarding retrofits, EPA believes the financial markets will supply adequate capital for units pursuing retrofits under the final Transport Rule.  
Permit Approval, PUC Approval, Existing Permits - Time Issues
   EPA acknowledges that the time required for air permit approval varies from state to state.  Many states established programs to aid the utility sector in complying with regulations.  For instance, Indiana allows application for "Interim Approval" to commence construction, Pennsylvania allows expedited review, and Michigan, by policy, attempts to complete permit to install (PTI) within 6 months and usually takes less than 60 days. States implementing "lean" permitting principles achieved significant reductions in permit processing times.  Three of four states (MI, ID, IN) typically process the permit in under 150 days; the fourth state (IA) does it in 180 days. Moreover, the agency plans to issue guidance for permitting authorities and thereby reduce burdens and shorten time requirements.  For a more detailed discussion, see Preamble section VII.I.1.  
   
   NSR permitting is discussed in Preamble section VII.I.2.  
   
   State pre-construction permitting requirements depend upon each individual state. Deregulated states (IL, NJ, NY, OH, PA) and regulated states (AL, CO, FL, GA, MN, MO, NC, VA) do not require pre-construction permits while some other states (IN, KY, MD, WI) require PUC (public utility commission) approval.  For states obtaining PUC pre-approval for cost recovery, authorization typically averages 6 months and is obtained usually within one.    Furthermore, while PUC approval is necessary to recover investment costs through rate payers, it is not a prerequisite for obtaining credit or performing conceptual studies.  
   
   A covered unit's existing permit limitations do not exempt the utility from Transport Rule compliance; rather, if permit revision is deemed necessary, the owner is expected to amend the permit and seek regulatory approval for the revision.  During CAIR implementation, utilities obtained state commission approval and financing; therefore, EPA believes the Transport Rule's requirements, with respect to the level and timing of reductions, are reasonable and consistent with the direction and timing of prior rulemakings and legal settlements, as evidenced by EPA's projections showing that the majority of the most likely units to consider cost-effective retrofits under the Transport Rule either conducted retrofit planning or even partial construction efforts previously or are already under an existing consent decree to install such retrofits in the future (see preamble section VII.C.2 for more information).  
Project Execution Issues Necessitate Long Time Periods
   Numerous commenters claimed that actual project execution timeframes exceeded the time allotted by the proposed rule.  To illustrate the point, commenters referenced specific retrofit project elements with asserted time requirements for their completion as part of the retrofitting process.  EPA recognizes that retrofitting EGUs with pollution control technology requires a substantial amount of labor hours from a multitude of skill sets.  However, EPA's schedule length assumptions for SO2 post-combustion projects relevant to this rulemaking are fully compatible with total labor hours required for completion. Project schedule length is heavily influenced by resource dedication and execution method.  While any project can be executed at a slow pace, the EGU pollution controls industry developed into a mature industry in response to the Acid Rain Program, the NOX SIP Call, and CAIR with the ability to perform accelerated project execution using a faster and more efficient Design-Build process.  The power sector has recognized considerable efficiency gains through integrating standardized equipment designs, systems approach, and modular construction techniques as well as the formation of business alliances to reduce frictional time lags.
   
   A typical control retrofit project consists of the following elements, several of which may occur simultaneously:  site studies, conceptual engineering, equipment sizing, cost estimating, planning, detailed design, procurement, construction, commissioning / testing, and permit application. For design-build methodology, the project is divided into two major phases: pre-award work requiring minor expenditures (site studies, conceptual engineering, equipment sizing, cost estimates, schedule planning) and award work requiring significant capital commitment (detailed design, procurement, construction, commissioning / testing).  Pre-award work elements are typically executed sequentially since each preceding stage's results inform the following stage; however, award work elements can be executed with "Lean Construction" techniques to shorten time frames. Since a typical emission control device is a combination of smaller independent sub-systems, the design / build process with "lean construction" is highly suited for retrofits.  For instance, a wet FGD's chimney, scrubber, landfill, reagent preparation, rail car unloading, waste water treatment, and dewatering facility occupy different plant site locations; thereby, allowing simultaneous design, procurement, construction, and testing activities.  To illustrate the point, Asheville Power station FGD retrofit was completed on a 26 month schedule, and an AEP unit in Brilliant, Ohio required only 18 months to complete construction on a wet FGD retrofit.  (For additional retrofit examples, see preamble section VII.C.2)
   
   EPA does not agree with commenters that lengthy retrofit schedules from various individual prior projects are dispositive of the power sector's ability to install cost-effective retrofits under the Transport Rule's schedule.  In particular, such examples cited by commenters fail to account for the adoption of proven faster execution methods evidenced by numerous units that have demonstrated FGD retrofit project completion in less than 30 months.  In particular, commenters who cite examples of lengthy or delayed retrofit schedules from projects conducted during the highly uncertain period of the CAIR remand (when it was prudent to proceed cautiously) cannot reasonably expect such experiences to apply to retrofit project execution with the benefit of renewed regulatory certainty gained by promulgation of the final Transport Rule (when it is prudent to proceed expeditiously and with confidence).
Claims of Infeasibility for 2014 Compliance
   While the timeframe imposed by the final rule is ambitious, EPA believes it can be met.  A project's completion time is a function of an owner's decisions; examples of long completion timeframes offer more of a window into project management preferences rather than minimum time requirements to complete the retrofit project expeditiously.  The utility can encourage faster project completion by stipulating penalties during contract negotiation for failing to achieve commercially available dates.  EPA believes completion of these retrofit projects is feasible by 2014 based on several previous retrofit projects that were successfully deployed within the timeframe allowed.  In fact, the wet FGD at Homer City unit 3 was placed in service 29 months after project award.  With the massive build-out over the past decade for CAIR, the engineering, procurement, and construction sector for controls equipment developed into a mature industry with many suppliers and options to select.  As observed during implementation of CAIR, significant deployments were achieved in response to the NOX SIP Call which yielded notable efficiencies in retrofit deployments, allowing for shorter project completion timelines.  Given the considerable experience and skills obtained by the power sector and the pollution control suppliers during this time period, EPA believes that the Transport Rule offers an acceptable deployment schedule for the projected retrofit installations in the least-cost compliance pathway modeled for the final Transport Rule.   (For more discussion, see preamble section VII.C.2).  As described in that section, EPA analyzed the scenario in which FGD retrofitting in 2014 is not feasible (an assumption that EPA does not agree with) but where sources are still required to comply with Transport Rule emission budgets.  The results indicate that covered units would still be able to meet Transport Rule requirements in 2014, without any new FGD retrofits, while respecting each state's assurance levels.
Claims of Infeasibility for 2012 Compliance
   The Jan 1, 2012 reductions projected by IPM are based on: 1) operating existing installed controls; 2) completing installation of previously announced control retrofits coming online by 2012; 3) Fuel switching / blending; and 4) installing combustion controls such as low NOX burners, overfire air or a combination thereof.   EPA believes that these reduction strategies are feasible by the start of the Transport Rule programs in 2012; for more discussion, see preamble section VII.C.2.
Inadequate Labor Pool, Low Skill Level & Insufficient Equipment Suppliers
   With current unemployment rates, sufficient quantities of engineers and skilled craft exist for Transport Rule implementation. Likewise, for the extreme case of local labor shortages (which is not anticipated), this challenge can be overcome by instituting a workforce development action plan during project execution.  This sector's equipment suppliers and manufacturers are underutilized since 2010.
Long Lead Times for Key Components
   Multiple public commenters express concern with the delivery of equipment in time to meet compliance dates.  In particular, UARG provided a table showing the increase in order lead time for ball mills, rubber lined pumps, air compressors, and internal recycle alloy spray headers due to heavy construction activity between 2003 and 2006.  This table can be reviewed in its original context in Coal Power's publication; "Plant Economics  -  The Impact of Shortages on FGD Prices" Table #1, by Steve Katzberger, Sept 1, 2007.  This comment selectively focuses on this table to claim that there is insufficient time available for equipment delivery to comply with the rule.  However, earlier in that article, a bar chart illustrates year-by-year announced FGD start-ups from 2006 through 2015 for CAIR compliance. Clearly, the long lead times tabulated for Dec 2006 reflect the more than 80 FGD systems expected to be in-service for 2008 and 2009.  EPA's projections of least-cost compliance with the Transport Rule's state budgets include only 5.7 GW of wet FGD retrofits by 2014; if we put that level of effort into the context of the historical data presented by the article's graph on lead times, the projected FGD deployment for the Transport Rule is similar to the article's 2006 FGD in-service projections, which required a 1 year lead time for equipment (Table 1, column Oct 2005).  Furthermore, the longest lead time item (rubber lined recycle pumps) within Katzenberger's article required 112 weeks for delivery; the final Transport Rule is being promulgated 30 months (or 130 weeks) ahead of the start of the 2014 control period  -  this still allows 18 weeks (even under Katzberger's lead times) to install, test, and commission the pumps.  In addition, the commenter does not cite any estimates of current lead times for equipment affecting retrofit deployment; rather, the commenter asserts future infeasibility by relying on outdated information which EPA believes does not accurately characterize the current state of the market or the opportunities for efficient and expeditious retrofit deployment discussed above and in section VII.C.2 of the final Transport Rule preamble.  
Multi-unit Stations  -  More Time Required
   EPA acknowledges that some of the plants that choose to retrofit with FGD control systems may wish to retrofit more than one unit on the plant site at the same time. EPA expects that in many cases it will be possible and economic to combine emissions from several units into a larger control device. In such combined multi-unit cases the installation time should be only slightly greater than for a single unit, and still feasible for compliance by 2014. In any event, a multi-unit retrofit on one site has significant execution cost and schedule advantages not realized at multiple single unit stations through aggregating resources to create economies of scale. These include one-time mobilization, extended equipment rental, dedicated staging area, efficient skilled craft utilization, and reduced administrative outlays. Furthermore, units can be "tied-in" sequentially, avoiding a complete station shutdown during installation.  Successful examples include Dickerson Station's three 190 MW units feed a single scrubber which discharges into a single flue stack.  Chalk Point station's two units share a single common wet FGD.   FirstEnergy's Sammis station's wet scrubber project combined emissions from seven units into three absorbers while AEP's Clifty Creek and Kyger Creek stations will employ similar design concepts for their wet FGDs. 
Commissioning / Start-up - Time Requirements
   Commissioning equipment is an essential part of project completion.  EPA acknowledges the time required for testing pollution control systems may span weeks or months.   Individual components can be inspected and pre-tested during construction activities to determine faulty equipment.  Commissioning involves testing and fine tuning the entire system while firing fuel. Therefore, the pollution controls equipment is fully functional and removing pollution. Consequently, emissions are reduced during the commissioning phase.  The Transport Rule does not impose any specific "deadline" on units to finish commissioning a retrofit that the owners select as a cost-effective reduction strategy under a state's emissions budgets.  In fact, as the retrofitting units are taken offline for final tie-in and are subsequently tested with the new pollution control equipment, their emissions are likely to decrease substantially, which is fully compatible with the start of the Transport Rule programs, when each ton emitted would require the utility to submit an allowance (which has market value).  Therefore, if a unit requires additional time leading into the beginning of 2014 to complete these final, low- or no-emitting phases of the retrofitting activity, that unit would potentially have even lower emissions in 2014 than it would have had it completed the retrofit on schedule.  EPA does not believe, therefore, that commissioning or start-up time scheduling pose a material concern to Transport Rule compliance.
ESP Upgrades Required for Fuel Switching
   Several commenters indicated fuel switching may require electrostatic precipitator (ESP) upgrades.  Not all ESP's require improvements due to fuel switching / blending since: 1) an existing ESP may have sufficient design / operating margins to accommodate increased particulate loading, and 2) the presence of a wet FGD augments PM control equipment by effectively removing particulate matter itself.  For those cases requiring upgrade, numerous ESP suppliers and after market businesses exist to perform upgrades.  EPA does not believe, therefore, that an ESP upgrade is a necessary step for all units considering emission reductions from fuel switching under the Transport Rule, and where it may be necessary, EPA believes such units can readily upgrade their ESPs while making cost-effective emission reductions in response to the Transport Rule state budgets.  For example, AEP's Amos Power Plant refurbished an ESP within six months.  
FRP pipe  -  Insufficient Specialized Skilled Craft for Installation
   Commenters identified concerns about insufficient quantities of special skilled labor for installing and erecting fiberglass resin pipe (FRP) pipe.  Most FRP pipe manufacturers offer installation training at the construction site or at the supplier's premises, such as Ward Piping. 
Fuel / Coal Switching or Blending Issues
   Multiple commenters were concerned about difficulties involving fuel switching.  EPA models fuel switching as either a complete fuel change or blending an existing fuel stock with a lower sulfur source.  Blending is acceptable for compliance and complete fuel switching with associated plant modifications may be unnecessary.  EPA carefully considered the feasibility of coal switching when analyzing the availability of cost-effective reductions in each state in 2012 and 2014.  For more information, on fuel switching / blending, see preamble section VII.C.2.c.  For IPM modeling basis regarding fuel switching / blending, see  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" contained in the docket.
Landfills - Construction Time Requirements
   The compliance deadline allows sufficient time for completing landfills for FGD solids disposal.  For example, DP&L will construct a landfill within 18 months to accept wastes generated from Stuart and Killen stations scrubbers.  EPA notes, however, that retrofitting units do not necessarily need to complete landfill construction ahead of commencing operation of the retrofit to achieve cost-effective emission reductions under the Transport Rule programs.  Such a source may either utilize a completed portion of the newly permitted landfill under construction, transfer waste off-site to a permitted landfill within the owner's fleet, or contract waste removal (and disposal) services.  For example, Dallman station subcontracts coal ash disposal at local abandoned mine.  EPA uses a disposal cost assumption of $30-$50 per ton for wet FGD, dry FGD, and DSI controls, which EPA developed in consultation with an experienced power sector engineering firm.  
Low NOX Burners - Installation Time Requirements
   According to ICAC, low NOX burner installation requires between 6-8 months.   With extensive low NOX burners retrofitted across the coal-fired EGU industry during the past three decades, EPA considers this a mature technology which can be economically and reliably installed within the allotted timeframe for compliance.  See preamble section VII.C.2. 
SNCR - Installation Time Requirements
   SNCR retrofit can typically be completed within 8 months.  Due to its simplicity and extensive installations, EPA considers this a mature technology which can be economically and reliably installed within the allotted timeframe for compliance.  See preamble section VII.C.2. 
Stack / Chimney - Construction Time Requirements
   EPA acknowledges that a wet FGD requires a "wet" stack which typically incorporates a fiberglass resin pipe (FRP) liner.  The commenter's claim that chimney engineering and construction require more than 30 months is inaccurate.  Chimney size is determined by the scrubber's location and discharge flow conditions, which the utility determines early on in the retrofit planning process and conceptual engineering design.  Chimney construction can utilize the "slip form" method to reduce erection time, with assembly typically requiring less than 60 days.    For instance, the Fayette power station stack #4 was poured within 39 days and Kiewit Power construction teams poured the Sandy Creek Energy Station chimney (height: 360 feet) in less than 30 days. Dallman's 440 ft unit #4 chimney required 28 days for erection.   Thus, chimney engineering and construction are easily subsumed in the overall FGD deployment process that itself can be completed in less than 30 months.
CAIR Suffices... Transport Rule Not Required
   The court in North Carolina identified several fatal flaws with CAIR, and remanded the rule so that EPA could develop a replacement consistent with the court's opinion.  Please see Preamble section IV.B and V.B for a more thorough discussion.

Emission Control Capabilities 
SCR Capability
   The Transport Rule's SCR NOX removal rates are consistent with commercially available equipment from multiple manufacturers.  In fact, current technology is capable of removing up to 90% of incoming NOX (subject a floor limit of 0.06 lbm NOX / MMBtu) on a continuous basis.  The utility is responsible for ensuring that the system design accounts for all factors leading to degraded performance over the expected life of the SCR system.  
   EPA does not see any technical basis for claims that units originally designed for partial year operation would experience NOX removal difficulties under all-year operation. 
   
   Properly operated and maintained SCR's are capable of meeting their continuous design rating basis for NOX reduction (subject to floor limitations). 
SNCR Capability
   EPA examined the performance of existing SNCR at coal fired boilers covered by the Transport Rule.  The units analyzed consisted of circulating fluidized bed, tangential fired, dry bottom wall fired, cell burners, cyclone burners, dry bottom vertically fired, dry bottom turbo fired, and stoker fired boilers.  EPA considered hourly electronic emissions data as reported to the Clean Air Markets Division and assumed that SNCR operation occurred only during the ozone season.  By comparing the heat input-weighted average NOX emission rates between the ozone season and non-ozone season for calendar years 2000-2010, the analysis determined that overall SNCR removal efficiency averaged 35.6% (within an observed range of 15-78%).  Based on this analysis, the EPA concludes that its SNCR removal efficiency assumptions represent real-world SNCR performance and are appropriate for Transport Rule promulgation.
WFGD Capability
   Current original equipment manufacturers (OEM) commercially offer (and advertise) wet FGD technology that is capable of removing 98% of SO2.  For older wet FGDs, two options exist for enhancing performance: utilizing dibasic acid and / or upgrading internal components.    Other commenters observed that EPA's dry and wet FGD removal rate assumptions in the proposal's power sector modeling reflected guaranteed performance levels (which depend upon particular fuels and operating loads, among other factors), while continuous in-service removal rates are typically lower, as the "guaranteed performance" level is not easily sustained in normal operations.  In response to this comment, EPA decreased its removal rate assumptions for modeling emission reductions from dry and wet FGD retrofits.  For more discussion, see "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule," in the docket for this rulemaking. .  

Implementation Costs
Breaking Contracts  -  Existing Fuel Purchasing Agreements
   Numerous commenters argued that the EPA failed to examine the financial implications for early termination of existing fuel contracts  -  so called "breach" of contract penalties - to achieve emission reductions through fuel switching.  EPA does not believe it is necessary for units to break existing fuel contracts for several reasons.  First, the utility sector purchases 20% of its fuel from spot markets, and 97% of new fuel contracts are short term (less than 5 yrs). Also, the electric power sector manages fuel contracts through a tiered (or layered) structure that does not lock in the total fuel portfolio at a given unit for long periods of time (as various portions of that portfolio come up for contract renewal at frequent intervals).  Utilities therefore have a large degree of existing flexibility in year-to-year fuel selection decisions even under existing contracts.  Secondly, units have the flexibility to determine what proportion of fuel blending is economic in response to the Transport Rule's state emission budgets, which does not prescribe a specific degree of fuel switching at any specific unit.  In addition, the Transport Rule's program structure offers the flexibility to purchase allowances as an interim measure if a utility desires extra time to negotiate a transition to new fuel contracts.  
Fiduciary Obligations Prevent Expenditures until Rule Finalized
   Multiple commenters claimed that making major capital expenses prior to the rule's promulgation would violate a public company's fiduciary obligations.  In all cases, the commenters failed to quantify the alleged financial burdens that they would incur to be positioned for expeditious compliance upon final promulgation.  EPA recognizes that unit owners must consider regulatory risk associated with making major investments in control equipment; however, the expenditures for determining potential retrofit requirements (pre-award work) are minimal, with conceptual engineering studies accounting for less than 1% of total installed cost.  For example, Nebraska Public Power District (NPPD) commissioned a $2.4 million study to develop a "ready to issue" contract for an FGD retrofit estimated to cost $1 billion for the 1,365 MW Gerald Gentleman Station.  This represents 0.24% of installed cost.  Since conceptual engineering is necessary to assess potential unit modification options, EPA believes that these pre-award minor expenditures do not violate fiduciary obligations; rather, they provide valuable information for future planning for regulatory compliance, which appears to serve a sensible fiduciary purpose. 
   
Inflationary Pressures
   EPA's modeling of the final Transport Rule projects significantly fewer units selecting pollution control retrofits as a cost-effective emission reduction strategy, as compared to EPA's projections at proposal.  Consequently, EPA does not anticipate cost escalation (inflationary pressures) from market suppliers.  See Transport Rule preamble Table VII.C.2-1: "Projected APC Retrofits for Transport Rule."
Retrofit Emissions Control Costs
   EPA recognizes that retrofit costs have aspects that are site-specific, depending in part on available space. EPA believes that the updated cost functions used to model projected retrofits for the final rule accurately represent recent industry cost outlays that themselves reflected site-specific cost drivers.  For a discussion on retrofit cost modeling, please see "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule".  
Transport Rule  -  Harmful to Economy
   EPA projects that the benefits to the public of the final Transport Rule far exceed the rule's limited costs.  Please see the final Transport Rule RIA for presentation of the rule's projected costs, benefits, and economic impacts.

Switching from Lignite to Subbituminous

      Commenters have questioned whether or not EPA's modeling of available emission reductions has accurately captured the cost-effectiveness of increasing sub-bituminous consumption at units currently blending various shares of Texas lignite.  While EPA believes that its main analyses of the Transport Rule accurately reflect the most cost-effective SO2 reductions available to Texas at the stringency level of a Group 2 state, in response to these concerns, EPA also conducted sensitivity analysis to address the cost-effectiveness of units continuing to blend lignite coal under the 2012 SO2 budget for Texas in the final rule.  The purpose of this analysis is to determine if the Transport Rule's SO2 assurance level for Texas is robust to varying levels of blending lignite and sub-bituminous coals at Texas facilities; in other words, the analysis investigates whether other cost-effective emission reductions exist in Texas aside from coal-switching to meet the state's Transport Rule SO2 assurance level in 2012.
      In this analysis, EPA constrained Texas units from increasing their blending of sub-bituminous coal beyond the level each unit reported to EIA for 2010.  This is a conservative scenario for fuel blending, as EIA data shows that these units have significantly increased their level of sub-bituminous blending over several years leading to 2010 and thus already exhibit a multi-year trend of decreasing lignite consumption before the Transport Rule was promulgated.  For the purposes of this sensitivity analysis, however, their sub-bituminous blending is prevented from growing beyond 2010 levels, notwithstanding the trend through 2010.  Under these conditions, Texas is still projected to meet its 2012 SO2 assurance level using other cost-effective emission reduction strategies, including greater dispatch from lower-emitting generators, while still maintaining 2010 lignite blending levels.  The sensitivity analysis reveals that Texas can still achieve its assurance level with other emission reductions available at the same marginal cost shared by all Group 2 states.  That common marginal cost (the projected Group 2 SO2 allowance price in 2012) remains about $600 in both the main Transport Rule remedy analysis and this lignite-blending sensitivity analysis.  Therefore, this analysis shows that the Texas SO2 assurance level is robust across a wide spectrum of lignite and sub-bituminous blending levels at Texas units.
      Texas is still projected in this sensitivity scenario to emit less SO2 than its assurance level in both 2012 and 2014, even with its EGUs continuing to consume in the future the level of lignite reported to EIA in 2010.  This sensitivity analysis therefore shows that Texas can sustain the operation of lignite mines and the provision of lignite coal to Texas EGUs while still cost-effectively meeting the Transport Rule's emission reduction requirements.  Also, coal-switching is only one of many ways by which Texas can comply; EPA data show that 75% of Texas coal capacity will be scrubbed by 2012 and analysis shows that those units can increase their generation.  Finally, natural gas-fired units benefiting from substantially expanding Texas natural gas supplies and low near-term prices can also increase their generation to help Texas cost-effectively meet its 2012 SO2 budget.  The following table presents the key parameters from this analysis supporting EPA's conclusion that Texas can still cost-effectively comply with the Transport Rule even while maintaining the level of Texas lignite production and EGU blending reported in 2010 into the 2012 and 2014 compliance periods.
      
                  Key Findings from Texas Lignite Sensitivity
 
                                     2012
                                     2014
 
                               Remedy (revised)
                           Texas Lignite Sensitivity
                               Remedy (revised)
                           Texas Lignite Sensitivity
Group 2 Allowance Price
                                     $573 
                                     $581 
                                     $651 
                                     $659 
Texas SO2 Emissions*
                                    244,000
                                    280,000
                                    266,000
                                    281,000
Texas lignite production (million tons)
                                     27.4
                                     42.3
                                     34.4
                                     47.5
Change in Texas lignite production from 2010 levels**
                                     -14.1
                                      0.8
                                     -7.1
                                      6.0
*The 2012 and 2014 SO2 assurance level for Texas is 288,000 tons.
**EIA reported 2010 Texas lignite deliveries of 41.5 million tons.
Note:  Remedy (revised) results are taken from the "TR_Remedy_Sensitivity_with_final_variability_limits" IPM run in the docket, whose results are also presented in Appendix F of the RIA.  Texas Lignite Sensitivity results are taken from the "TR_Remedy_Sensitivity_Subbit_Restrictions" IPM run in the docket.
      
      As these results show, even with Texas lignite blending at or above reported 2010 levels in the 2012 and 2014 compliance periods, Texas SO2 emissions remain below the state's assurance level and the Group 2 allowance price remains very stable, showing that Texas is still making cost-effective reductions to meet its Transport Rule obligations.  The results in the table also demonstrate that Texas can achieve cost-effective compliance across a wide range of possible lignite production levels in the future, further demonstrating that the Transport Rule is not foreclosing the potential for Texas units to consume lignite coal.  More details regarding this analysis can be found in the IPM model output files included in the docket for this rulemaking.
      EPA believes this sensitivity analysis demonstrates the flexibility that is inherent in the Transport Rule programs as applied to Texas coal choice specifically and applied to all states covered by the Transport Rule more broadly.  While EPA established emission reduction requirements for the states based on its modeling of the most cost-effective reductions available at cost thresholds used to define each state's significant contribution and interference with maintenance, EPA chose to implement these emission reduction requirements as state emission budgets under which units can choose from a variety of emission reduction behaviors.  This program design allows units to consider all relevant local economic factors when making dispatch, retrofit, and/or coal choice decisions factoring in the programs' market-based cost of emitting SO2 and NOX.
      In addition, with the flexibility to submit a SIP to determine its preferred allowance allocation pattern beginning in 2013 under EPA's expedited allowance allocation SIP process, Texas (as well as other states) has the freedom to augment preferred compliance activities as the state sees fit.
Plant Modifications -  Switching from 100% Lignite to 100% Subbituminous 
      A few commenters expressed concern about the technical feasibility of switching to 100% subbituminous coal use in power plants that were originally designed for 100% lignite and are currently burning either 100% lignite or a blend of lignite and subbituminous.  EPA carefully considered these comments and has confirmed its IPM modeling assumption that units designed for 100% lignite can readily switch to 100% subbituminous, or to a blend, by making relatively minor physical modifications that can be accomplished within the time frame available for compliance with the Transport Rule. 
      A noteworthy example of a full switch from lignite to 100% subbituminous is the 480 MW Gibbons Creek station of Texas Municipal Power Agency (TMPA): "In 1996, TMPA management switched exclusively to PRB [Powder River Basin] coal to improve the economics of Gibbons Creek and to lower SO2 emissions. The switch required relatively minor changes to the physical plant and its control systems. Only one of the original eight mills was removed from service, although only five mills are needed for full load operation using PRB coal as fuel."
      EPA understands that the primary reason that large pulverized coal boilers designed for a lower grade coal (lignite) can readily burn a higher grade coal (subbituminous) without major modifications is that in almost all respects such units are already "over designed" as regards the capabilities needed to successfully burn the higher grade coal. This fact is most apparent in comparing boiler furnace sizes: the plan area and height of a furnace designed for low-slagging lignite are at least as large as needed for subbituminous, and the dimensions of a high-slagging lignite furnace may be as much as 50% larger than needed for subbituminous.  Similarly, the lower heating value of lower rank lignite requires that a lignite unit's coal handling systems, pulverizers, boiler draft fans, air emission controls, and ash handling systems already have significantly greater capacity than needed for subbituminous. Lignite units that are currently blending a significant share of subbituminous have likely already made the important but relatively minor improvements in coal handling and dust suppression systems needed to safely accommodate the friability and dusting associated with subbituminous.  Because of its low heating value, the rail transport cost for lignite is relatively high and lignite plants are therefore typically located close to local lignite mines, so called "mine mouth" plants  -  often trucking or conveying coal to the plant. Switching from lignite to a subbituminous that comes from more distant sources may therefore entail some improvement to the rail spur and coal receiving system at some plants. These transport and coal handling requirements may already be in place at many lignite plants. Aside from these fundamental requirements, the more important modifications that may be required to facilitate a successful switch to subbituminous is the minor upgrading of current boiler cleaning systems to modern "water cannons" and "intelligent sootblowing" systems to cope with various issues that might arise due to the slagging potential or higher "ash reflectivity" of subbituminous coal. 
      For all of the reasons discussed above, EPA believes that a switch from lignite to 100% subbituminous coal or to a blend with subbituminous is a technically feasible  compliance option that can be accomplished at most lignite plants within the time frames available under the Transport Rule. Lignite units choosing to make a switch to higher grade subbituminous coal would be expected to experience reductions in total coal consumption and air pollutant emissions, an increase in boiler efficiency, and an increase in net electrical output.