# Kentucky Energy and EnvironmentCabinet
Kentucky Division for Air Quality



# -------------------------------------------

Appendix H.5 Excerpts from Clean Air
Interstate Rule Preamble - EPA Cost Analysis

## [This page intentionally left blank.]

## Thursday,
May 12, 2005



# Part II



# Environmental Protection Agency

40 CFR Parts 51, 72, et al. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NO X 

## SIP Call; Final Rule


### 25162 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

**ENVIRONMENTAL PROTECTION AGENCY** 

**40 CFR Parts 51, 72, 73, 74, 77, 78 and 96** 

**[OAR–2003–0053; FRL–7885–9]**

**RIN 2060–AL76**

**Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone**  **(Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the**  **NO** X **SIP Call**

**AGENCY :**  Environmental Protection Agency (EPA).

**ACTION :**  Final rule.

**SUMMARY :**  In today’s action, EPA finds that 28 States and the District of Columbia contribute significantly to nonattainment of the national ambient air quality standards (NAAQS) for fine particles (PM 2.5 ) and/or 8-hour ozone in downwind States. The EPA is requiring these upwind States to revise their State implementation plans (SIPs) to include control measures to reduce emissions of sulfur dioxide (SO 2 ) and/or nitrogen oxides (NO X ). Sulfur dioxide is a precursor to PM 2.5 formation, and NO X is a precursor to both ozone and PM 2.5 formation. Reducing upwind precursor emissions will assist the downwind PM 2.5 and 8-hour ozone nonattainment areas in achieving the NAAQS. Moreover, attainment will be achieved in a more equitable, cost-effective manner than if each nonattainment area attempted to achieve attainment by implementing local emissions reductions alone.

Based on State obligations to address interstate transport of pollutants under section 110(a)(2)(D) of the Clean Air Act (CAA), EPA is specifying statewide emissions reduction requirements for SO 2 and NO X . The EPA is specifying that the emissions reductions be implemented in two phases. The first phase of NO X reductions starts in 2009 (covering 2009–2014) and the first phase of SO 2 reductions starts in 2010 (covering 2010–2014); the second phase of reductions for both NO X and SO 2 starts in 2015 (covering 2015 and thereafter). The required emissions reductions requirements are based on controls that are known to be highly cost effective for electric generating units (EGUs).

Today’s action also includes model rules for multi-State cap and trade programs for annual SO 2 and NO X emissions for PM 2.5 and seasonal NO X emissions for ozone that States can choose to adopt to meet the required emissions reductions in a flexible and cost-effective manner. Today’s action also includes revisions to the Acid Rain Program regulations under title IV of the CAA, particularly the regulatory provisions governing the SO 2 cap and trade program. The revisions are made because they streamline the operation of the Acid Rain SO 2 cap and trade program and/or facilitate the interaction of that cap and trade program with the model SO 2 cap and trade program included in today’s action. In addition, today’s action provides for the NO X SIP Call cap and trade program to be replaced by the CAIR ozone-season NO X trading
program.

**DATES :**  The effective date of today’s action, except for the revisions to 40 CFR parts 72, 73, 74, and 77 of the Acid Rain Program regulations, is July 11, 2005. States must submit to EPA for approval enforceable plans for complying with the requirements of this rule by September 11, 2006. The effective date for today’s revisions to 40 CFR parts 72, 73, 74, and 77 of the Acid Rain Program regulations is July 1, 2006.

**ADDRESSES :**  The EPA has established a docket for this action under Docket ID No. OAR–2003–0053. All documents in the docket are listed in the EDOCKET index at http://www.epa.gov/edocket

. Although listed in the index, some information is not publicly available, i.e. , Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically in EDOCKET or in hard copy at the EPA Docket Center, EPA West, Room B102, 1301 Constitution Avenue, NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the Air Docket is (202) 566–1742.

**FOR FURTHER INFORMATION CONTACT :**  For general questions concerning today’s action, please contact Carla Oldham, U.S. EPA, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, Mail Code C539–02, Research Triangle Park, NC, 27711, telephone (919) 541–3347, e-mail
at oldham.carla@epa.gov. For legal questions, please contact Sonja Petersen, U.S. EPA, Office of General Counsel, Mail Code 2344A, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 564–4079, e-mail at petersen.sonja@epa.gov. For questions regarding air quality analyses, please contact Norm Possiel, U.S. EPA, Office of Air Quality Planning and Standards, Emissions Monitoring and Analysis Division, Mail Code D243–01, Research Triangle Park, NC, 27711, telephone (919) 541–5692, e-mail at possiel.norm@epa.gov. For questions regarding the EGU cost analyses, emissions inventories, and budgets, please contact Roman Kramarchuk, U.S. EPA, Office of Atmospheric Programs, Clean Air Markets Division, Mail Code 6204J, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 343–9089, e-mail at kramarchuk.roman@epa.gov. For questions regarding statewide emissions inventories, please contact Ron Ryan, U.S. EPA, Office of Air Quality Planning and Standards, Emissions Monitoring and Analysis Division, Mail Code D205– 01, Research Triangle Park, NC, 27711, telephone (919) 541–4330, e-mail at ryan.ron@epa.gov. For questions regarding emissions reporting requirements, please contact Bill Kuykendal, U.S. EPA, Office of Air Quality Planning and Standards, Emissions Monitoring and Analysis Division, Mail Code D205–01, Research Triangle Park, NC, 27711, telephone (919) 541–5372, e-mail at kuykendal.bill@epa.gov. For questions regarding the model cap and trade programs, please contact Sam Waltzer, U.S. EPA, Office of Atmospheric Programs, Clean Air Markets Division, Mail Code 6204J, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 343–9175, e-mail at waltzer.sam@epa.gov. For questions regarding analyses required by statutes and executive orders, please contact Linda Chappell, U.S. EPA, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, Mail Code C339–01, Research Triangle Park, NC, 27711, telephone (919) 541–2864, e-mail at chappell.linda@epa.gov. For questions regarding the Acid Rain Program regulation revisions, please contact Dwight C. Alpern, U.S. EPA, Office of Atmospheric Programs, Clean Air Markets Division, Mail Code 6204J, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 343–9151, e-mail at alpern.dwight@epa.gov

. **SUPPLEMENTARY INFORMATION :**  Regulated Entities

Except for the revisions to the Acid Rain Program regulations, this action does not directly regulate emissions sources. Instead, it requires States to


## [This page intentionally left blank.]

### 25197 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

Register , EPA is publishing a proposal to include Delaware and New Jersey in the CAIR region for annual SO 2 and NO X reductions.) The addition of these three States made a total of 26 States and the District of Columbia covered by annual SO 2 and NO X caps for the initial model run. The initial model run also included individual State ozone season NO X caps for Connecticut and Massachusetts, and did not include ozone season NO X caps for any other States.

The Agency conducted revised final IPM modeling that reflects the final CAIR control strategy. The final IPM modeling includes regionwide annual SO 2 and NO X caps on the 23 States and the District of Columbia that are required to make annual reductions, and includes a regionwide ozone season NO X cap on the 25 States and the District of Columbia that are required to make ozone season reductions. The EPA modeled the final CAIR NO X strategy as an annual NO X cap with a nested, separate ozone season NO X cap.

In this section of today ’ s preamble, the projected CAIR costs and emissions are generally derived from the final IPM run reflecting the final CAIR. However, some of EPA ’ s analyses are based on the initial IPM run, described above, which reflected a similar but not identical control strategy to the final CAIR. Analyses that are presented in this section of the preamble that are based on the initial IPM run include: IPM sensitivity runs that examine the effects of using the Energy Information Administration (EIA) natural gas price and electricity growth assumptions; marginal cost effectiveness curves developed using the Technology Retrofitting Updating Model; estimates of average annual SO 2 and NO X control costs and average non-ozone season NO X control costs, and projected control retrofits used in the feasibility analysis. The air quality analysis in section VI of today ’ s preamble and the benefits analysis in section X, as well as the analyses presented in the Regulatory Impact Analysis (RIA), are based on emissions projections from the initial IPM run.

The EPA believes that the differences between the initial IPM run that the Agency used for many of the analyses for the CAIR, and the final IPM run reflecting the final CAIR requirements, have very little impact on projected control costs and emissions. For the two IPM runs, projected marginal costs of CAIR annual NO X reductions in 2009 and 2015 are identical. In addition, for the two IPM runs, projected marginal costs of CAIR annual SO 2 reductions in 2010 and 2015 are almost identical. Also, the 2009 and 2015 projected annual NO X emissions in the region encompassing the States that are affected by the final CAIR annual NO X requirements are virtually identical when compared between the two model runs (difference between projected NO X emissions is less than 1 percent for 2009 and less than 2 percent for 2015). In addition, the 2010 and 2015 projected annual SO 2 emissions in the region encompassing the States that are affected by the final CAIR annual SO 2 requirements are virtually the same when compared between the two runs (difference between projected SO 2 emissions is less than 1 percent for 2010 and less than 2 percent for 2015). These comparisons confirm EPA ’ s belief that the initial IPM run very closely represents the final CAIR program.

The IPM output files for the model runs used in CAIR analyses are available in the CAIR docket. A Technical Support Document in the CAIR docket entitled ‘‘ Modeling of Control Costs, Emissions, and Control Retrofits for Cost Effectiveness and Feasibility Analyses ’’ further explains the IPM runs used in the analyses for section IV of the preamble.

2. The EPA ’ s Proposed Methodology To Determine Amounts of Emissions That Must be Eliminated a. Overview of EPA Proposal for the Levels of Reductions and Resulting Caps, and Their Timing

In the NPR, the amounts of SO 2 and NO X emissions reductions that EPA proposed could be cost effectively eliminated in the CAIR region in 2010 and 2015, and the amount of the proposed EGU emissions caps for SO 2 and NO X that would exist if all affected States achieved those reductions by capping EGU emissions, appear in Tables IV

– 1 and IV

– 2, respectively.



### T ABLE 

### IV

– 1.

— P ROJECTED 

### SO 2 AND 

### NO X 

### E MISSION 

### R EDUCTIONS IN THE 

### CAIR R EGION IN 

### 2010 AND 

### 2015

FOR THE 

### P ROPOSED 

### R ULE [Million Tons] 1

Pollutant 2010 2015

SO 2

................... 3.6 3.7 NO X

.................. 1.5 1.8

1 CAIR Notice of Proposed Rulemaking (69 FR 4618, January 30, 2004). The proposed annual SO 2 and NO X caps covered a 27-State (AL, AR, DE, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MN, MO, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI) plus DC region. In addition, we proposed an ozone-season only cap for Connecticut. 

### T ABLE 

### IV

– 2.

— P ROPOSED 

### A NNUAL 

### E LECTRIC 

### G ENERATING 

### U NIT 

### SO 2 AND 

### NO X 

### E MISSIONS 

### C APS IN THE 

### CAIR R EGION [Million Tons] 1

Pollutant 2010

– 2014 2015 and later

SO 2

................... 3.9 2.7 NO X

.................. 1.6 1.3

1 CAIR Notice of Proposed Rulemaking (69 FR 4618, January 30, 2004). The proposed annual SO 2 and NO X caps covered a 27-State (AL, AR, DE, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MN, MO, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI) plus DC region. In addition, we proposed an ozone-season only cap for Connecticut.

In the NPR, EPA evaluated the amounts of SO 2 and NO X emissions in upwind States that contribute significantly to downwind PM 2.5 nonattainment and the amounts of NO X emissions in upwind States that contribute significantly to downwind ozone nonattainment. That is, EPA determined the amounts of emissions reductions that must be eliminated to help downwind States achieveattainment, by applying highly costeffective control measures to EGUs and determining the emissions reductions that would result.

From past experience in examining multi-pollutant emissions trading programs for SO 2 and NO X , EPA recognized that the air pollution control retrofits that result from a program to achieve highly cost-effective reductions are quite significant and can not be immediately installed. Such retrofits require a large pool of specialized labor resources, in particular, boilermakers, the availability of which will be a major limiting factor in the amount and timing of reductions.

Also, EPA recognized that the regulated industry will need to secure large amounts of capital to meet the control requirements while managing an already large debt load, and is facing other large capital requirements to improve the transmission system. Furthermore, allowing pollution control retrofits to be installed over time enables the industry to take advantage of planned outages at power plants (unplanned outages can lead to lost revenue) and to enable project management to learn from early installations how to deal with some of the engineering challenges that will exist, especially for the smaller units that often present space limitations.

Based on these and other considerations, EPA determined in the NPR that the earliest reasonable deadline for compliance with the final


### 25198 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

highly cost-effective control levels for reducing emissions was 2015 (taking into consideration the existing bank of title IV SO 2 allowances). First, the Agency confirmed that the levels of SO 2 and NO X emissions it believed were reasonable to set as annual emissionscaps for 2015 lead to highly costeffective controls for the CAIR region.

Once EPA determined the 2015 emissions reductions levels, the Agency determined a proposed first (interim) phase control level that would commence January 1, 2010, the earliest the Agency believed initial pollution controls could be fully operational (in today ’ s final action, the first NO X control phase commences in 2009 instead of in 2010, as explained in detail in section IV.C). The first phase would be the initial step on the slope of emissions reductions (the glide-path) leading to the final (second) control phase to commence in 2015. The EPA determined the first phase based on the feasibility of installing the necessary emission control retrofits, as described in section IV.C.

Although EPA ’ s primary costeffectiveness determination is for the 2015 emissions reductions levels, the Agency also evaluated the cost effectiveness of the first phase control levels to ensure that they were also highly cost effective. Throughout this preamble section, EPA reports both the 2015 and 2010 (and 2009 for NO X ) costeffectiveness results, although the first phase levels were determined based on feasibility rather than cost effectiveness. The 2015 emissions reductions include the 2010 (and 2009 for NO X ) emissions reductions as a subset of the more stringent requirements that EPA is imposing in the second phase. b. Regulatory History: NO X SIP Call

In the NPR, EPA generally followed the statutory interpretation and approach under CAA section 110(a)(2)(D) developed in the NO X SIP Call rulemaking. Under this interpretation, the emissions in each upwind State that contribute significantly to nonattainment are identified as being those emissions thatcan be eliminated through highly costeffective controls.

In the NO X SIP Call, EPA relied primarily on the application of highly cost-effective controls in determining the amount of emissions that the affected States were required to eliminate. Specifically, EPA developed a reference list of the average cost effectiveness of recently promulgated or proposed controls, and compared the cost effectiveness of those controls to the cost effectiveness of the NO X SIP Call controls under consideration. In addition, EPA considered several other factors, including the fact that downwind nonattainment areas had already implemented ozone controls but upwind areas generally had not, the fact that some otherwise required local controls would be less cost-effective than the regional controls, and the overall ambient effects of the reductions required in the NO X SIP Call (63 FR
57399

– 57403; October 27, 1998). i. Highly Cost-Effective Controls

In the NO X SIP Call, EPA presented control costs in 1990 dollars (1990$). For the electric power industry, these expenditures were the increase in annual electric generation production costs in the control region that result from the rule. In the CAIR NPR, SNPR, and today ’ s final action, EPA presents the same type of electric generation as well as other costs in 1999$, and rounds all values related to the cost per ton of air emissions controls to the nearest 100 dollars.

In the NO X SIP Call, EPA ’ s decision on the amount of required NO X emissions reductions was that this amount must be computed on the assumption of implementing highly cost-effective controls. The determination of what constituted highly cost effective controls was described as a two-part process: (1) The setting of a dollar-limit upper bound of highly cost-effective emissions reductions; and (2) a determination ofwhat level of control below this upperbound was appropriate based upon achievability and other factors.

With respect to setting the upper bound of potential highly cost-effective controls, EPA determined this level on the basis of average cost effectiveness (the average cost per ton of pollutant removed). The EPA explained that it relied on average cost effectiveness for
two reasons:

Since EPA ’ s determination for the core group of sources is based on the adoption of a broad-based trading program, average cost effectiveness serves as an adequate measure across sources because sources with high marginal costs will be able to take advantage of this program to lower their costs. In addition, average cost-effectiveness estimates are readily available for other recently adopted NO X control measures (63 FR 57399).

At that time, EPA acknowledged that average cost effectiveness did not directly address the fact that certain units might have higher costs relative to the average cost of reduction ( e.g. , units with lower capacity factors tend to have higher costs): [I]ncremental cost effectiveness helps to identify whether a more stringent control option imposes much higher costs relative to the average cost per ton for further control. The use of an average cost effectiveness measure may not fully reveal costly incremental requirements where control options achieve large reductions in emissions (relative to the baseline) (63 FR 57399).

Examination of marginal cost effectiveness

—which examines what the cost would be of the next ton of reduction after the defined control level

—would fill this gap. However, for the NO X SIP Call rulemaking, adequate information concerning marginal cost effectiveness was not available.

For the NO X SIP Call, to determine the average cost effectiveness that should be considered to be highly cost effective, EPA developed a ‘‘ reference list ’’ of NO X emissions controls that are available and of comparable cost to other recently undertaken or planned NO X measures. The EPA explained that

‘‘ the cost effectiveness of measures that EPA or States have adopted, or proposed to adopt, forms a good reference point for determining which of the available additional NO X control measures can most easily be implemented by upwind States whose emissions impact downwind nonattainment problems. ’’ (63 FR 57400). The EPA explained that the measures on the reference list had already been implemented or were planned to be implemented, and therefore could be assumed to be less expensive than other measures to be implemented in the future. The EPA found that the costs of the measures on the reference list approached but were below $2,000 per ton (1990$). The EPA concluded that ‘‘ controls with an average cost effectiveness [of] less than $2,000 [1990$, or $2,500 (1999$)] per ton of NO X removed [should be considered] to be highly cost-effective. ’’ (63 FR 57400). Notably, the reference costs were taken from the supporting analyses used for the regulatory actions covering the NO X pollution controls

— they are what regulatory decision makers and the public believed were the control costs.

Mindful of this $2,000 limit [1990$, or $2,500 (1999$)], EPA considered a control level that would have resulted in estimated average costs of approximately $1,800 (1990$) per ton. However, EPA concluded that because the corresponding level of controls

— nominally a 0.12 lb/mmBtu control level

—was not well enough established, EPA was ‘‘ not as confident about the robustness ’’ of the cost estimates. Moreover, EPA expressed concern that its ‘‘ level of comfort ’’ was not as high as


## [This page intentionally left blank.]

### 25201 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

56 The updated reference list includes estimated average costs for SO 2 reductions from EGUs under best available retrofit technology (BART) requirements. The BART rule was proposed and has not been finalized (69 FR 25184; May 5, 2004). controls that are a step that the Agency is taking at this time to eliminate emissions that contribute significantly to nonattainment of the ozone and fine particle NAAQS. As explained elsewhere, this step is reasonable in light of the current status of implementation for those NAAQS.

Basing emission reduction requirements on a presumption of BACT emission rates across the board wouldrequire scrubbers and SCRs on all coalfired units and SCRs on all gas-fired and oil-fired units. The cost of these controls would vary considerably from source to source, be expensive for many sources, and may cause substantial fuel switching to natural gas and closure of smaller coal-fired units. Having considered this suggestion for deeper regional reductions that would not be as cost effective as the highly cost-effective reductions in today ’ s rule, EPA believes that a more tailored approach, such as the CAIR level control as well as local controls under SIPs (where necessary), is a more reasonable approach to achieving the level of ambient improvement needed for attainment throughout the United States.

4. The EPA ’ s Evaluation of Highly CostEffective SO 2 and NO X Emissions Reductions Based on Controlling EGUs

a. SO 2 Emissions Reductions Requirements i. CAIR Proposal for SO 2

The NPR focused primarily on determining highly cost-effective amounts of emissions reductions based on, as in the NO X SIP Call, comparison to reference lists of the cost effectiveness of other regulatory controls. In the NPR, EPA developed reference lists for both the average cost effectiveness and the marginal cost effectiveness of those other controls. These reference lists indicated that the average annual costs per ton of SO 2 removed ranged from $500 to $2,100; and marginal costs of SO 2 removal ranged from $800 to $2,200.

Moreover, EPA further considered the cost effectiveness of alternative stringency levels for this regulatory proposal. That is, EPA examined changes in the marginal cost curve at varying levels of emissions reductions. The EPA determined in the NPR that the

‘‘ knee ’’ in the marginal costeffectiveness curve

— the point at which the marginal cost per ton of SO 2 removed begins to increase at a noticeably higher rate

— appears to start above $1,200 per ton (69 FR 4613

— 4615).

In the NPR, EPA then provided further analysis of a two-phase SO 2 reduction program. The final (second) phase, in 2015, would reduce SO 2 emissions in the CAIR region by the amount that results from making a 65 percent reduction from the title IV Phase II allowance levels (taking into consideration the existing bank of title IV SO 2 allowances). The first phase, in 2010, would reduce SO 2 emissions in the CAIR region by a lesser amount, i.e.

, a 50 percent reduction from title IV Phase II allowance levels (again, taking into consideration the banked title IV SO 2 allowances). The EPA developed this target SO 2 control level for further evaluation because, based on all of theearlier work performed on multipollutant power plant reduction programs and general consideration, with technical support, of overall emissions reductions, costs to industry and the general public, ambient improvement, and consistency with the emerging PM 2.5 implementation program, we believed it would meet the criteria set forth above.

Then, EPA conducted cost analyses of this control level using the IPM as well as additional analysis of the implications of this control level to determine if it did indeed meet those criteria. The IPM analysis considered the increase in annual electric generation production costs in the CAIR region that result from the rule. The EPA evaluated the cost effectiveness of the final phase (2015) cap to determine if it is highly cost effective; and, we also evaluated the cost effectiveness of the 2010 cap. The EPA used the IPM to estimate cost effectiveness of the CAIR in the future. The IPM incorporates projections of future electricity demand, and thus heat input growth. The EPA ’ s IPM analyses for the CAIR includes all fossil fuel-fired EGUs with capacity greater than 25 MW. A description of the IPM is included elsewhere in this preamble, and a detailed model documentation is in the docket.

The SO 2 annual control costs that were presented in the CAIR NPR were average costs of $700 per ton and $800 per ton for years 2010 and 2015, respectively, and marginal costs of $700 per ton and $1,000 per ton for years 2010 and 2015. In addition, the NPR included the results of sensitivity analyses that examined costs of the proposed SO 2 controls based on the Energy Information Administration ’ s projections for electricity growth and natural gas prices. These sensitivity analyses showed marginal SO 2 control costs of $900 per ton and $1,100 per ton for years 2010 and 2015, respectively. The EPA proposed to consider the SO 2 emissions reductions proposed in the NPR as highly cost effective because they were consistent with the lower end of the reference list range of cost per ton of SO 2 reduction for controls on both an average and a marginal cost basis (69 FR
4613

— 4615). ii. Analysis of SO 2 Emission Reduction Requirements for Today ’ s Final Rule
(I) Reference Lists of Cost-Effective SO 2 Controls

For today ’ s action, EPA updated the reference list of controls included in the NPR of the average and marginal costs per ton of recent SO 2 control actions. The EPA systematically developed a list of cost information from both recent actions and proposed actions. The EPA compiled cost information for actions taken by the Agency, and examined the public comments submitted after the NPR was published, to identify all available control cost information to provide the updated reference list for today ’ s preamble. The updated reference list includes both average and marginal costs of control, to which EPA compares the CAIR control costs, and the list represents what regulatory decision makers and/or the public believes are the control costs. 56

Table IV

– 3 provides average costs of SO 2 controls. This table includes average costs for recent BACT permitting decisions for SO 2 . Under EPA ’ s New Source Review (NSR) program, if a company is planning to build a new plant or modify an existing plant such that a significant net increase in emissions will occur, the company must obtain a NSR permit that addresses controls for air emissions. BACT is the type of control required by the NSR program for existing sources in attainment areas. The BACT decisions are determined on a case-by-case basis, usually by State or local permitting agencies, and reflect consideration of average and incremental cost effectiveness. These decisions are relevant for EPA ’ s reference list of average costs of SO 2 controls, because they represent cost-effective controls that have been demonstrated.


### 25202 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

57 The EPA used the difference between EIA ’ s estimates for well-head natural gas prices and minemouth coal prices to determine the sensitivity of IPM ’ s results to higher natural gas prices. The EPA describes this sensitivity analysis as ‘‘ EIA natural gas prices ’’ . For electric demand, we replaced EPA ’ s assumed annual growth of 1.6 percent with EIA ’ s projection of annual growth of 1.8 percent. 

### T ABLE 

### IV

– 3.

—A VERAGE 

### C OSTS PER 

### T ON OF 

### A NNUAL 

### SO 2 

### C ONTROLS

SO 2 control action Average cost per ton

Best Available Control Technology (BACT) Determinations ........................................................................

................................. 1 $400

– $2,100 Nonroad Diesel Engines and Fuel ................................................................................................

................................................ 2 $800 Proposed Best Available Retrofit Technology (BART) for Electric Power Sector ...................................................

..................... 3 $2,600

– $3,400

1 These numbers reflect a range of cost-effectiveness data entered into EPA ’ s RACT/BACT/LAER Clearinghouse (RBLC) for add-on SO 2 controls ( www.epa.gov/ttn/catc/ ). We identified actions in the data base for large, utility-scale, coal-fired boiler units for which cost effectiveness data were reported. The range of costs shown here is for boilers ranging from 30 MW to an estimated 790 MW (we used a conversion factor of 10 mmBtu/hr = 1 MW for units for which size was reported in mmBtu/hr). Emission limits for these actions ranged from 0.10 lb/mmBtu to 0.27 lb/ mmBtu. Add-on controls reported for these units are dry or wet scrubbers (in one case with added alkali and in one case with a baghouse). Where the dollar-year was not reported we assumed 1999 dollars. The cost range presented in the NPR was $500

– $2,100

–today ’ s range includes additional BACT costs that were entered into the clearinghouse after the NPR was published.

2 Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; Final Rule (69 FR 39131; June 29, 2004). The value in this table represents the long-term cost per ton of emissions reduced from the total fuel and engine program (cost per ton of emissions reduced in the year 2030). 1999$ per ton.

3 The EPA IPM modeling 2004, available in the docket. The EPA modeled the Regional Haze Requirements as source specific limits (90 percent SO 2 reduction or 0.1 lb/mmBtu rate; except the five state WRAP region for which we did not model SO 2 controls beyond what is done for the WRAP cap in the base case modeling). Estimated average costs based on this modeling are $2,600 per ton in 2015 and $3,400 per ton in 2020. 1999$ per ton.

Table IV

– 4 provides the marginal cost per ton of recent State and regional decisions for annual SO 2 controls.



### T ABLE 

### IV

– 4.

— M ARGINAL 

### C OSTS PER 

### T ON OF 

### A NNUAL 

### SO 2 

### C ONTROLS

SO 2 control action Marginal cost per ton

New Hampshire Rule .............................................................................................................

........................................................ 1 $600 WRAP Regional SO 2 Trading Program ................................................................................................................

......................... 2 $1,100

– $2,200

1 The EPA IPM base case modeling August 2004, available in the docket. (1999$ per ton). We modeled New Hampshire ’ s State Bill ENVA2900, which caps SO 2 emissions at all existing fossil steam units.

2 ‘‘ An Assessment of Critical Mass for the Regional SO 2 Trading Program, ’’ prepared for Western Regional Air Partnership Market Trading Forum by ICF Consulting Group, September 27, 2002, available in the docket. This analysis looked at the implications of one or more States choosing to opt-out of the WRAP regional SO 2 trading program. (1999$ per ton)

(II) Cost Effectiveness of the CAIR Annual SO 2 Reductions

In the NPR, EPA evaluated an annual SO 2 control strategy based on a specified level of emissions reductions from EGUs. Available information indicated that emissions reductions from this industry would be the most cost effective. (As noted elsewhere, EPA considered control strategies for other source categories, but concluded thatthey would not qualify as highly costeffective controls.) Of course, under today ’ s rule, although EPA calculates the amount of emissions reductions States must achieve by evaluation of the EGU control strategy, States remain free to achieve those reductions by implementing controls on any sources they wish.

For today ’ s action, EPA updated the predicted annual SO 2 control costs included in the NPR. The EPA analyzed the costs of the CAIR using an updated version of the IPM (documentation for the IPM update is in the docket). Further, EPA modified the modeling to match the final CAIR strategy (see section IV.A.1 for a description of EPA ’ s CAIR IPM modeling). The EPA also updated its analysis of the sensitivity of the marginal cost results to assumptions of higher electric growth and natural gas prices than we used in the base case. These sensitivity analyses were based on the Energy Information Administration ’ s Annual Energy Outlook for 2004. 57

In determining whether our control strategy is highly cost effective, EPA believes it is important to account for the variable levels of cost effectiveness that these sensitivity analyses indicate may occur if electricity demand or natural gas prices are appreciably higher than assumed in the IPM. Those two factors are key determinants of control costs and, over the relatively long implementation period provided under today ’ s action, a meaningful degree of risk arises that these factors may well vary to the extent indicated by the sensitivity analyses. As a result, EPA wanted to examine the marginal costs that would occur under the scenarios modeled in the sensitivity analyses to see how they differed from the costs using EPA ’ s assumptions.

Table IV

– 5 provides the average and marginal costs of annual SO 2 reductions under the CAIR for 2010 and 2015. (When presenting estimated CAIR control costs in section IV of this preamble, EPA uses ‘‘ Main Case ’’ to indicate the primary CAIR IPM analyses, as differentiated from other IPM analyses such as sensitivity runs used to examine the impacts of varying assumptions about natural gas price and electric growth.)



### T ABLE 

### IV

– 5.

— E STIMATED 

### C OSTS 

### P ER



### T ONS OF 

### SO 2 

### C ONTROLLED 

### U NDER 

### CAIR, C AP 

### L EVELS 

### B EGINNING IN 

### 2010 AND 

### 2015 1

Type of cost effectiveness 2010 2015

Average Cost

— Main Case $500 $700 Marginal Cost

— Main Case 700 1,000


### 25203 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

58 The updated reference list of average SO 2 control costs includes estimated average EGU costs under BART. The BART rule has been proposed but not finalized (69 FR 25184; May 5, 2004). 59 EPA did promulgate Phase I of the ozone implementation rule in April 2004 (69 FR 23951; April 30, 2004) but has not issued Phase II of the rule, which will interpret CAA requirements relating to local controls ( e.g., RACT, RACM, RFP). 

### T ABLE 

### IV

– 5.

— E STIMATED 

### C OSTS 

### P ER



### T ONS OF 

### SO 2 

### C ONTROLLED 

### U NDER 

### CAIR, C AP 

### L EVELS 

### B EGINNING IN 

### 2010 AND 

### 2015 1



### — Continued

Type of cost effectiveness 2010 2015

Sensitivity Analysis: Marginal Cost Using EIAElectric Growth and Natural Gas Prices ............. 800 1,200

1 The EPA IPM modeling 2004, available in the docket. $1999 per ton.

These estimated SO 2 control costs under the CAIR reflect annual EGU SO 2 caps of 3.6 million tons in 2010 and 2.5 million tons in 2015 within the CAIR region. Based on IPM modeling, EPA projects that SO 2 emissions in the CAIR region will be about 5.1 million tons in 2010 and 4.0 million tons in 2015. The projected emissions are above the cap levels because of the use of the existing title IV bank of SO 2 allowances. Average costs shown for 2015 are an estimate of the average cost per ton to achieve the total difference in projected emissions between the base case conditions and the CAIR in the year 2015 (the 2015 average costs are not based on the increment in reductions between 2010 and 2015). (A more detailed description of the final CAIR SO 2 and NO X control requirements is provided below in today ’ s preamble.)
(III) SO 2 Cost Comparison for CAIR Requirements

The EPA believes that if an SO 2 control strategy has a cost effectiveness that is at the low end of the updated reference tables, the approach should be considered to be highly cost effective. The costs in the reference range should be considered to be cost effective because they represent actions that have already been taken to reduce emissions. In deciding to require these actions, policymakers at the local, State and Federal levels have determined them to be cost-effective reductions to limit or reduce emissions. Thus, costs at the bottom of the range must necessarily be considered highly cost effective.

Today ’ s action requires SO 2 emissions reductions (or an EGU emissions cap) in 2015. The EPA has determined that those emissions reductions are highly cost effective. In addition, today ’ s action requires that some of those SO 2 emissions reductions (or a higher EGU emissions cap) be implemented by 2010. The EPA has examined the cost effectiveness of implementing those earlier emissions reductions (or cap) by 2010, and determined that they are also highly cost effective. The cost of the SO 2 reductions required under today ’ s action

— if the States choose to implement those reductions through EGUs, for which the most cost-effective reductions are available

— on average and at the margin, are at the lower end of the range of cost effectiveness of other, recent SO 2 control requirements. 58 This is true for our analysis of both the costs EPA generally expects as well as the somewhat higher costs that would result from higher than expected electricity demand and natural gas prices, as indicated in the sensitivity analyses that EPA has done.

Specifically, the average cost effectiveness of the SO 2 requirements is $700 per ton removed in 2015. This amount falls toward the low end of the reference range of average costs per ton removed of $400 to $3,400. Similarly, the marginal cost effectiveness of the SO 2 requirements ranges from $1,000 to $1,200 for 2015 (with the higher end of the range based on the sensitivity analyses). These amounts fall toward the lower end of the reference range of marginal cost per ton removed of $600 to $2,200.

The EPA believes that selecting as highly cost-effective amounts toward the lower end of our average and marginal cost ranges for SO 2 and NO X control is appropriate because today ’ s rulemaking is an early step in the process of addressing PM 2.5 and 8-hour ozone nonattainment and maintenance requirements. The CAA requires States to submit section 110(a)(2)(D) plans to address interstate transport, and overall attainment plans to ensure the NAAQS are met in local areas. By taking the early step of finalizing the CAIR, we are requiring a very substantial air emission reduction that addresses interstate transport of PM 2.5 as well as a further reduction in interstate transport of ozone beyond that required by the NO X SIP Call Rule. Much of the air quality improvement resulting from reduced transport is likely to occur through broad and deep emissions reductions from the electric power sector, which has been a major part of the transport problem. Other air quality benefits will occur as the result of Federal mobile source regulations for new sources, which cover passenger vehicles and light trucks, heavy-duty trucks and buses, and non-road diesel equipment.

Against this backdrop of Federal actions that lower air emissions (as well as some substantial State control programs), States will develop plans designed to achieve the standards in their local nonattainment areas. The EPA has not yet promulgated rules interpreting the CAA ’ s requirements for SIPs for PM 2.5 and ozone nonattainment

areas, 59 nor have States developed plans to demonstrate attainment. As a result, there are significant uncertainties regarding potential reductions and control costs associated with State plans. We believe that some areas are likely to attain the standards in the near term through early CAIR reductions and local controls that have costs per ton similar to the levels we have determined to be highly cost effective. We expect that other areas with higher PM 2.5 or ozone levels will determine through the attainment planning process that they need greater emissions reductions, at higher costs per ton, to reach attainment within the CAA ’ s timeframes. For those areas, States will need to assess targeted measures for achieving local attainment in a cost-effective (but not necessarily highly cost-effective) manner, in combination with the CAIR ’ s significant reductions. Given the uncertainties that exist at this early stage of the implementation process, EPA believes this rule is a rational approach to determining the highly cost-effective reductions in PM 2.5 and ozone precursors that should be required for interstate transport purposes.

As discussed above, the Agency believes this approach is consistent with our action in the NO X SIP Call. While the cost level selected for the NO X SIP Call was not at the low end of the reference range of costs, if the NO X SIP Call costs were for annual rather than seasonal controls they would have been lower relative to the annual control costs on the list. This would make the relationship between the cost of the NO X SIP Call and the reference costs used in that rulemaking, more similar to relative costs of CAIR compared to its reference lists. Also, significant local controls for meeting the 1-hour ozone standard had already been adopted in
many areas.

Although EPA ’ s primary costeffectiveness determination is for the 2015 emissions reductions levels, the Agency also evaluated the cost effectiveness of the interim phase control levels to ensure that they were also highly cost effective. For the SO 2 requirements for 2010, the average cost effectiveness is $500 per ton removed, and the marginal cost effectiveness


### 25204 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

60 EPA is using the knee in the curve analysis solely to show that the required emissions reductions are very cost effective. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. It should be noted that similar analysis for other source categories may yield different curves. ranges from $700 to $800. The 2010 costs indicate that the interim phaseCAIR reductions are also highly costeffective. (IV) Cost Effectiveness: Marginal Cost Curves for SO 2 Control

As noted above, the Agency also considered another factor to corroborate its conclusion concerning the cost effectiveness of the selected levels of control:

The cost effectiveness of alternative stringency levels for today ’ s action. Specifically, EPA examined changes in the marginal cost curve at varying levels of emissions reductions for EGUs. Figure IV

– 1 shows that the ‘‘ knee ’’ in the 2010 marginal cost-effectiveness

curve

— the point where the cost of controlling a ton of SO 2 from EGUs is increasing at a noticeably higher rate

— appears to occur at about $2,000 per ton of SO 2 . Figure IV

– 2 shows that the

‘‘ knee ’’ in the 2015 marginal costeffectiveness curve also appears to occur at about $2,000 per ton of SO 2 . (As discussed above, the projected marginal costs of SO 2 reductions for the CAIR are $700 per ton in 2010 and $1,000 per ton in 2015.) The EPA used the Technology Retrofitting Updating Model (TRUM), a spreadsheet model based on the IPM, for this analysis. (The EPA based these marginal SO 2 cost-effectiveness curves on the electric growth and natural gas price assumptions in the main CAIR IPM modeling run. Marginal cost effectiveness curves based on other electric growth and natural gas price assumptions would look different, therefore it would not be appropriate to compare the curves here to the marginal costs based on the IPM modeling sensitivity run that used EIA assumptions.) These results make clear that this rule is very cost effective because the control level is below the point at which the cost begins to increase at a significantly higher rate.

In this manner, these results corroborate EPA ’ s findings above concerning the cost effectiveness of the emissions reductions. 60


### 25205 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

b. NO X Emissions Reductions Requirements i. The CAIR Proposal for NO X and Subsequent Analyses for Regionwide Annual and Ozone Season NO X Control Levels

In this section, EPA describes its proposed method for determining regionwide NO X control levels and the method used for the final CAIR.

In the CAIR NPR, EPA updated the reference list included in the NO X SIP Call for the average annual cost effectiveness of recent or proposed NO X controls, and determined that these amounts ranged from approximately $200 to $2,800. In addition, in the NPR, EPA developed a reference list for marginal annual cost effectiveness for NO X controls, and determined that these amounts ranged from approximately $1,400 to $3,000 (69 FR 4614

— 4615).

In the NPR, EPA proposed a twophased annual NO X control program, with a final phase in 2015 and a first phase in 2010. The regionwide emissions reduction requirements that EPA proposed

— and the budget levels that would apply if all States chose to implement the reductions from EGUs

— were based on using a combination of recent historical heat input and NO X emissions rates for fossil fuel-fired EGUs. For historical heat input, EPA proposed determining the highest heat input from units affected by the Acid Rain Program for each affected State for the years 1999

– 2002. The EPA then summed this heat input for all of the States affected for annual NO X reductions. For 2015, EPA calculated a proposed regionwide annual NO X budget by multiplying this heat input by an emission rate of 0.125 lb/mmBtu, and for 2010 by multiplying by 0.15 lb/ mmBtu.

In developing the CAIR NPR, when EPA considered the appropriate amount of annual SO 2 emissions reductions, EPA relied on the existing title IV annual SO 2 cap as a starting point. However, in considering the appropriate amount of NO X reductions, the situation is different because title IV does not cap NO X emissions. Therefore, EPA and the States have focused on emissions caps based on a combination of heat input and NO X emission rates. Emission rates similar to the rates used to develop the CAIR NPR have been considered in the past. For example, the CAPI 1996 study, noted above, contemplated NO X caps based on an emission rate of 0.15 lb/ mmBtu (and other options based on NO X rates of 0.20 lb/mmBtu and 0.25 lb/ mmBtu). The NO X SIP Call is based on an emission rate of 0.15 lb/mmBtu.

The methodology described in the NPR is best understood as the means for developing the target 2015 annual NO X control level (or emissions budget) for further evaluation through IPM. The EPA developed this level mindful of its experience to date with the NO X SIP Call and the earlier work EPA has performed on multi-pollutant power plant reduction programs. The EPA also considered available technical information on pollution controls, costs to industry and the general public, ambient air improvement, and consistency with the emerging PM 2.5 implementation program, in developing its target control level.

Recent advances in combustion control technology for NO X reductions, as well as widespread use of selectivecatalytic reduction (SCR) on U.S. coalfired EGU boilers achieving NO X emission rates of 0.06 lb/mmBtu and below, provide evidence that even lower average NO X emission rates are more highly cost-effective than rates considered in the past (based on analyzing EGUs), possibly on the order of 0.12 lb/mmBtu or less. The EPA developed the target annual NO X control level (or emissions budget) with


### 25206 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

61 The EPA does not collect annual heat input data from these non-Acid Rain units. EIA does collect heat input from such units, however there are some limitations to the data. First, there are no requirements specifying how the data should be collected or quality assured. Second, the data is collected on a plant-wide basis rather than on a unit-by-unit basis. 62 These projected average NO X emissions rates are from updated IPM modeling done in 2004. The IPM modeling done prior to the NPR also projected similar average emission rates, about 0.15 lb/ mmBtu and 0.11 lb/mmBtu in 2010 and 2015, respectively. the understanding that the evaluation of that level might indicate that average emission rates on the order of 0.12 lb/ mmBtu or less might be highly cost effective for the final (2015) control phase, and an interim level resulting in an average emission rate of less than 0.15 lb/mmBtu might be feasible for the first phase.

The EPA did evaluate the target annual NO X control levels (or emissions budgets) using the IPM. The EPA confirmed that the 2015 level is highly cost effective. The Agency also evaluated the cost effectiveness of the proposed 2010 cap to assure that the interim phase reductions would also be highly cost effective. The EPA ’ s IPM analyses for the CAIR includes all fossil fuel-fired EGUs with generating capacity greater than 25 MW.

The proposed cap for the first phase was developed taking into consideration how much pollution control for NO X and SO 2 could be installed without running into a shortage of skilled labor, in particular boilermakers (EPA ’ s assumptions regarding boilermaker labor are described in section IV.C.2 of this preamble). The Agency focused on providing substantial reductions of both SO 2 and NO X emissions at the outset of the proposed program, leading to significant retrofits of Flue Gas Desulfurization units (FGD) for SO 2 control and SCR for NO X control.

In the NPR, EPA explained that using the highest Acid Rain Program heat input for each State to develop a regionwide heat input amount, rather than the average Acid Rain Program heat input, provided a cushion that represented a reasonable adjustment to reflect that there are some non-Acid Rain units that operate in these States that will be subject to the proposed CAIR emission reduction levels. The EPA explained that it did not use heat input data from non-Acid Rain units in the proposal because it did not have all the necessary data available at the time the NPR was developed. 61 Using the highest of recent years ’ Acid Rain Program heat input provided an approximation of the regionwide heat input, although it did not include heat input from non-Acid Rain sources. Multiplying the approximate recent heat input by 0.125 lb/mmBtu to develop a proposed regionwide annual 2015 NO X cap could reasonably be expected to yield an average effective NO X emission rate (considering all EGUs potentially affected by CAIR for annual reductions, not only the Acid Rain units, and considering growth in heat input) somewhat less than 0.125 lb/mmBtu. Likewise, multiplying the approximate recent heat input by 0.15 lb/mmBtu to develop a regionwide annual 2010 NO X cap could reasonably be expected to yield an average effective NO X emission rate for all CAIR units of about 0.15 lb/ mmBtu or less.

Although EPA calculated

— in essence, as a target level for further evaluation

— the proposed regionwide annual NO X control levels (or emissions budgets) based on heat input from only Acid Rain Program units, the Agency evaluated the cost effectiveness of the control levels using heat input from all EGUs that potentially would be affected by the proposed CAIR. The EPA evaluated cost effectiveness using the IPM, which includes both Acid Rain units and non-Acid Rain units. Further, the IPM incorporates assumptions for electricity demand growth, and thus heat input growth.

Specifically, EPA evaluated these target annual NO X caps on EGUs for 2010 and 2015

— and therefore the associated regionwide emissions reductions

— using the IPM, which, in effect, demonstrated that these proposed NO X emissions cap levels can be met using highly cost-effective controls with the expected levels of electricity demand in 2010 and 2015, respectively. Those expected levels of electricity demand are higher than the electricity demand during the 1999 to 2002 years upon which EPA based heat input; and as a result, the amount of heat input necessary to meet the projected electricity demand is expected to be higher than the amount that EPA developed for evaluation purposes through the method described above. The projected average future emissions rates that would be associated with the 2010 and 2015 heat input levels needed to meet electricity demand (coupled with the NO X emissions budgets developed through the methodology described above) would be about 0.14 lb/mmBtu and 0.11 lb/mmBtu in 2010 and 2015, respectively. 62 These average rates would be for all units affected by annual NO X controls under CAIR, including non-Acid Rain units. Thus, the heat input is projected to be higher in 2010 and 2015 than the recent historic heat input used to develop the target emissions budgets, and the projected NO X emission rates in 2010 and 2015 are lower than the 0.15 lb/ mmBtu and 0.125 lb/mmBtu rates that were used to develop the budgets. IPM determined the costs of meeting these average future NO X emission rates of 0.14 lb/mmBtu and 0.11 lb/mmBtu. The EPA considers these emission rates to be highly cost-effective and feasible.

In the NPR, EPA proposed an interim (Phase I) annual NO X phase in 2010 and a final (Phase II) annual NO X phase in 2015. However, in today ’ s final rule, EPA is promulgating a Phase I for NO X in 2009 (with the Phase II for NO X in 2015, as proposed). The EPA determined the regionwide NO X control levels for 2009 and 2015 for today ’ s final action using the same methodology as we used to determine proposed levels. The Agency evaluated the cost effectiveness of the final reduction requirements (and average NO X emission rates) using IPM anddetermined them to be highly costeffective, assuming controls on EGUs. The EPA ’ s evaluation of the cost effectiveness of the emission reduction strategy we assumed in establishing the final CAIR control levels is discussed further below.

The average NO X emission rates in the first and second phases of CAIR will be lower than the nominal emission rate on which the NO X SIP Call was based, which was 0.15 lb/mmBtu. In the NO X SIP Call, EPA also considered a control level based on a lower nominal emission rate, 0.12 lb/mmBtu. However, at that time the use of SCR was not sufficiently widespread to allow EPA to conclude that the controls necessary to meet a tighter cap could be installed in the required timeframe, without causing reliability problems for the electric power sector. Now, through the experience gained from the NO X SIP Call, EPA has confidence that with SCR technology average emissions rates lower than the NO X SIP Call nominal emission rate can be achieved on a regionwide basis.

In the CAIR NPR, after determining the regionwide control level and evaluating it to assure that it is highly cost-effective, the Agency then apportioned the regionwide budgets to the affected States. The EPA proposed to apportion regionwide NO X budgets to individual States on the basis of each State ’ s share of recent average heat input. In the NPR, EPA used the average share of Acid Rain Program heat input. However, as discussed in the SNPR and the NODA, in order to distribute more equitably to States their share of the regionwide NO X budgets, EPA then


### 25207 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

63 The control costs for this model sensitivity that were presented in the NPR were in error (69 FR 4615). The corrected costs from the sensitivity are as shown here. considered each State ’ s proportional share of recent average heat input using data from non-Acid Rain Program sources as well as Acid Rain Program sources. The EPA obtained EIA heat input data reported for non-Acid Rain sources and combined the EIA heat inputs with Acid Rain heat inputs to determine each State ’ s share of combined average recent heat input.

The fact that EPA distributed the regionwide budget to individual States based on their proportional share of heat input from Acid Rain and non-Acid Rain units combined does not affect the determination of the regionwide budgets themselves. The regionwide budgetswere determined to be highly costeffective when tested for all units

— both non-Acid Rain units as well as Acid Rain units

— that would be affected by CAIR. (The EPA ’ s method for apportioning regionwide NO X budgets to States is discussed in more detail elsewhere in today ’ s preamble. That discussion includes an explanation of the differences between the State budgets that were presented in the NPR, the SNPR, and the NODA. In addition, see the TSD entitled ‘‘ Regional and State SO 2 and NO X Emissions Budgets. ’’ )

In the NPR, EPA proposed that Connecticut contributed significantly to downwind ozone nonattainment, but not to PM 2.5 nonattainment. Thus, the Agency proposed that Connecticut would not be subject to an annual NO X control requirement and was not included in the region proposed for annual controls. We proposed that Connecticut would be affected by an ozone season-only NO X control level, and proposed to calculate Connecticut ’ s ozone season control level in a parallel way to how the regionwide annual NO X control levels were calculated. That is, EPA selected the highest of the same 4 years of (ozone season-only) heat input used for the regionwide budget calculation, and multiplied that heat input by the same NO X emission rates used to calculate the regionwide control levels. Connecticut is the only State for which an ozone season budget was proposed.

The EPA used the same methodology for developing regionwide budgets for today ’ s final rule as was proposed in the NPR. For the final CAIR, EPA found that 23 States and the District of Columbia contribute significantly to downwind PM 2.5 nonattainment and found that 25 States and the District of Columbia contribute significantly to downwind ozone nonattainment (section III in today ’ s preamble describes the significance determinations). CAIR requires annual NO X reductions in all States determined to contribute significantly to downwind PM 2.5 nonattainment, and requires ozone season NO X reductions in all States determined to contribute significantly to downwind ozone nonattainment (many of the CAIR States are affected by both annual and ozone season NO X reduction requirements). The final CAIR ozone season NO X reductions are required in two phases, with Phase I commencing in 2009 and Phase II in 2015, the same years as the annual NO X reduction requirements.

As described above, the Agency proposed ozone season NO X reduction requirements for Connecticut, and did not propose separate ozone season reduction requirements in any other State. For today ’ s final rule, EPA requires ozone season reductions in all States contributing significantly to downwind ozone nonattainment. The EPA determined regionwide ozone season NO X control levels for the final CAIR using the same methodology as was used for the annual NO X reduction requirements (which is the same method that was proposed for Connecticut ’ s ozone season budget). That is, EPA determined the highest (ozone season) heat input from Acid Rain Program units for the years 1999

– 2002 for each State, then summed this heat input for all of the States affected for ozone season NO X reductions. For the final 2015 control level, EPA calculated a regionwide ozone season NO X budget by multiplying this heat input by an emission rate of 0.125 lb/ mmBtu, and for 2009 by multiplying by 0.15 lb/mmBtu. The Agency evaluated the cost effectiveness of these ozone season NO X control levels (and average NO X emission rates) using IPM anddetermined them to be highly costeffective, assuming controls on EGUs. The EPA ’ s evaluation of the cost effectiveness of the final CAIR control requirements is discussed further below.

Based on EPA ’ s analysis of proposed annual NO X control levels, in the NPR the Agency presented average costs for annual NO X control of $800 per ton and $700 per ton for 2010 and 2015, and marginal costs of $1,300 per ton and $1,500 per ton for 2010 and 2015. In the NPR, EPA also presented marginal costs of annual NO X control from sensitivity analyses that used EIA assumptions for electricity growth and natural gas prices. Those marginal control costs were $1,300 per ton and $1,600 per ton for 2010 and 2015, respectively. The EPA also presented costs from a sensitivity model run that used EIA assumptions for electricity growth and natural gas price and higher SCR costs. These marginal control costs were $1,700 per ton and $2,200 per ton for 2010 and 2015, respectively. 63

In the NPR, EPA also presented the average cost effectiveness for ozone season-only NO X control of $1,000 per ton and $1,500 per ton for 2010 and 2015, respectively, and a marginal cost for ozone season-only control of $2,200 per ton and $2,600 per ton for 2010 and 2015. The EPA also presented average costs for the non-ozone season (remaining seven months of the year) control of $700 per ton and $500 per ton in 2010 and 2015, respectively. (As noted above, the capital costs of installing NO X control equipment would be largely identical whether the equipment will be operated during the ozone season only or for the entire year. However, the amount of reductions would be less if the control equipment were operated only during the ozone season compared to annual operation.)

The EPA proposed the conclusion that these costs met the criteria for highly cost-effective emissions reductions for NO X (69 FR 4613

– 4615).

As with SO 2, EPA also considered the cost effectiveness of alternative stringency levels for this regulatory proposal (examining changes in the marginal cost curve at varying levels of emission reductions). ii. What Are the Most Significant Comments That EPA Received About Proposed NO X Emission Reduction Requirements, and What Are EPA ’ s Responses?

Some commenters expressed concern that EPA did not account for growth of heat input in calculating regionwide NO X emissions budgets, noting that growth was used in the calculation of the regional budget for the NO X SIP Call. Commenters suggest that, by not taking heat input growth into account, EPA developed regionwide budgets that are unduly stringent.

On the other hand, some commenters noted that they supported EPA ’ s proposal to base regionwide budgets on historical heat input and did not want EPA to use growth projections for calculating regionwide NO X emissions budgets. Some stated that using actual, historic heat input numbers would be more straightforward than using growth projections, and some pointed to complications with the growth projection methodologies used in the NO X SIP Call.

The EPA recognizes that it employed a growth factor in the NO X SIP Call.


### 25208 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

64 The updated reference list includes estimated average NO X control costs under BART. The BART rule has been proposed but not finalized (69 FR 25184; May 5, 2004). There, EPA determined the amount of the regional emissions reductions and budgets by applying a growth factor to a historic heat input baseline. The DC Circuit, after first remanding that growth methodology for a better explanation, upheld it. West Virginia v. EPA, 362 F.3d 861 (DC Cir., 2004). See 67 FR 21 868 (May 1, 2002).

For CAIR, as described above, EPA developed a target level for the proposed NO X regionwide cap based on recent historic heat input and assumed emission rates of 0.125 lb/mmBtu and 0.15 lb/mmBtu for 2015 and 2010, respectively. The EPA evaluated these target NO X emissions levels using IPM, which indicated that those target caps

— in conjunction with expected electricity demand for 2015 and 2010

—would result from higher heat input levels and lower average emissions rates (about 0.11 lb/mmBtu and 0.14 lb/mmBtu for 2015 and 2010, respectively) than the amounts assumed in developing the target NO X caps. Most importantly, IPM indicated the cost levels associated with those projected 2015 and 2010 average NO X emission rates, and EPA has determined that those cost levels are highly cost-effective. For the final rule, EPA revised its analyses to reflect the 2009 initial NO X control phase, and determined that the final CAIR requirements are highly cost-effective. The EPA ’ s methodology, in which the CAIR emissions reductions are predicted to be cost-effective under conditions of projected electricity growth that, in turn, projects heat input growth, in effect accounts for heat input growth. Moreover, the amount of heat input growth is the amount determined by IPM, a state-of-the-art model of the electricity sector (detailed documentation for IPM is in the docket).

Some commenters suggested that EPA adjust the NO X regionwide budget amounts to include heat input from non-Acid Rain units. For example, some suggested adding the non-Acid Rain unit heat input amounts that EPA used in apportioning regionwide NO X budgets to the States, to the total regionwide heat inputs that EPA used to calculate regionwide NO X budgets.

The regionwide budgets determined in the NPR were target levels developed as a starting point for further evaluation. The regionwide heat input amounts and NO X emission rates used to develop target budget levels were inherently imprecise. As discussed above, IPM modeling indicates that the projected future heat input amounts (based on electricity growth) are greater than the recent historic regionwide amount used to develop the target budget levels, and the future average emission rates for all units affected by CAIR annual NO X controls (including non-Acid Rain units) are less than the rates used to develop the target budget levels. IPM indicates that the target regionwide NO X budget levels (and corresponding future average NO X emission rates and heat input levels) are highly cost-effective for all CAIR units, including non-Acid Rain units. The EPA does not believe it is necessary to adjust the target regionwide budget levels to include the relatively small additional amount of heat input from non-Acid Rain units. The method the Agency used to develop target levels was not intended to be a precise methodology for determining the NO X caps; rather, it was a reasonable method for selecting a target level to be evaluated further. Upon evaluation of the target level, EPA determined that itcan be achieved using highly costeffective controls for all affected EGUs, including non-Acid Rain units. iii. Analysis of NO X Emission Reduction Requirements for Today ’ s Final Rule
(I) Reference Lists of Cost-Effective Controls

For today ’ s action, EPA updated the reference list of controls included in the NPR of the average and marginal costs per ton of recent NO X control actions. The EPA systematically developed a list of cost information from recent actions and proposed actions. The Agency sought cost information for actions taken by EPA, and examined the comments submitted after the NPR was published, to identify all available control cost information to provide the updated reference list for today ’ s preamble. The updated reference list includes both average and marginal costs of control to which EPA compares the CAIR control costs, although the Agency has limited information on marginal costs of other programs.

The EPA ’ s updated summary of average costs of annual NO X controls are shown in Table IV

– 6. The results of this reexamination show that costs of recent actions are generally very similar to those identified in the NO X SIP Call. The cost figures are presented in 1999 dollars. 64



### T ABLE 

### IV

– 6.

—A VERAGE 

### C OSTS PER 

### T ON OF 

### A NNUAL 

### NO X 

### C ONTROLS

NO X control action Average cost per ton

Marine Compression Ignition Engines .............................................................................................................................................. Up to $200 2 Off-highway Diesel Engine ...................................................................................................... ......................................................... $400

– $700 2 Nonroad Diesel Engines and Fuel ................................................................................................ ................................................... $600 1 Marine Spark Ignition Engines .................................................................................................. ....................................................... $1,200

– $1,800 2 Tier 2 Vehicle Gasoline Sulfur ................................................................................................. ......................................................... $1,300

– $2,300 2 Revision of New Source Performance Standards for NO X Emissions-EGUs ................................................................................. $1,700 3 2007 Highway Heavy Duty Diesel Standards ....................................................................................... ........................................... $1,600

– $2,100 2 National Low Emission Vehicle .................................................................................................. ...................................................... $1,900 2 Tier 1 Vehicle Standards ....................................................................................................... ........................................................... $2,100

– $2,800 2 Revision of New Source Performance Standards for NO X Emissions-Industrial Units ................................................................... $2,200 3 On-board Diagnostics ........................................................................................................... ............................................................ $2,300 2 Texas NO X Emission Reduction Grants FY 2002

– 2003 ................................................................................................................. $300

– $12,700 4 Best Available Retrofit Technology (BART) for Electric Power Sector ............................................................ ................................ $800 5

1 Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; Final Rule (69 FR 39131; June 29, 2004). The value in this table represents the long-term cost per ton of emissions reduced from the total fuel and engine program (cost per ton of emissions reduced in the year 2030). This value includes the cost for NO X plus NMHC reductions. 1999$ per ton.

2 Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements; Final Rule (66 FR 5102; January 18, 2001). The values shown for 2007 Highway HD Diesel Stds are discounted costs. Costs shown in this table include a VOC component. 1999$ per ton.


### 25209 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

65 The CSP consists of 200,000 tons, which is apportioned to each of the 23 States and the District of Columbia that are required by CAIR to make annual NO X reductions, as well as the 2 States (Delaware and New Jersey) for which EPA is proposing to require annual NO X reductions. 3 Proposed Revision of Standards of Performance for Nitrogen Oxide Emissions From New Fossil-Fuel Fired Steam Generating Units; P roposed Revision to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units; Proposed Rule (62 FR 36953; July 9, 1997), Table 4 (the Agency ’ s estimate of average control costs was unchanged for the NSPS revisions final rule, published September 5, 1998). In the CAIR NPR, we included a value from the range of NO X controls for coal-fired EGUs from Table 2 in the proposed NSPS proposed rule (62 FR 36951). 1999$ per ton.

4 Costs shown in this table are the range of project costs reported for projects that were FY 2002

– 2003 recipients of the TERP Emission Reductions Incentive Grants Program. These costs may not be in 1999 dollars. (www.tnrcc.state.tx.us/oprd/sips/grants.html)

5 The EPA IPM modeling 2004 of the proposed BART for the electric power sector (69 FR 25184, May 5, 2004), available in the docke t. The EPA modeled the Regional Haze Requirements as a source specific 0.2 lb/mmBtu NO X emission rate limit. Estimated average costs based on this modeling are $800 per ton in 2015 and 2020. 1999$ per ton.

Table IV

– 7 presents modeled marginal costs for recent State annual NO X rules.



### T ABLE 

### IV

– 7.

— M ARGINAL 

### C OSTS PER 

### T ON OF 

### R EDUCTION 

### , R ECENT 

### A NNUAL 

### NO X 

### R ULES

NOX control action Marginal cost per ton

Texas Rules .................................................................................................................... ............................................................... $2,000

– $19,600 1

1 The EPA IPM base case modeling August 2004, available in the docket. 1999$ per ton. We modeled Senate Bill 7 and Ch. 117, which impose varying NO X control requirements in different areas of the State; the range of marginal costs shown here reflects the range of requirements.

The EPA does not believe that it has sufficient information, for today ’ s rulemaking, to treat controls on source categories other than certain EGUs as providing highly cost-effective emissions reductions. The CAA Section 110 permits States to choose the sources and source categories that will be controlled in order to meet applicable emission and air quality requirements. This means that some States may choose to meet their CAIR obligations by imposing control requirements on sources other than EGUs.

As examples of cost-effective actions that States can take in efforts to provide for attainment with the air quality standards, Table IV

– 8 presents estimated average costs for potential local mobile source NO X control actions. The EPA received these cost data during the public comments on the
NPR.



### T ABLE 

### IV

– 8.

—A VERAGE 

### C OSTS OF 

### P OTENTIAL 

### L OCAL 

### M OBILE 

### S OURCE 

### C ONTROL 

### A CTIONS 

### T O 

### R EDUCE 

### NO X 

### E MISSIONS [$ per Ton] 1

Source category Average cost per ton

MWCOG Analysis: Mobile Source, Bicycle racks in DC .............................................................................

.................................. $9,000 MWCOG Analysis: Mobile Source, Telecommuting Centers ........................................................................... ............................. 7,300 MWCOG Analysis: Mobile Source, Government Action Days (ozone action days) ......................................................

............... 5,000 MWCOG Analysis: Mobile Source, Permit Right Turn on Red ........................................................................

............................. 1,200 MWCOG Analysis: Mobile Source, Employer Outreach ...............................................................................

................................ 3,500 MWCOG Analysis: Mobile Source, Mass Marketing Campaign .........................................................................

.......................... 2,900 MWCOG Analysis: Mobile Source, Transit Prioritization ..........................................................................

.................................... 8,500

1 Washington DC Metro Area MWCOG Analysis of Potential Reasonably Available Control Measures (RACM). Projects determined to be ‘‘ Possible ’’ by MWCOG but not RACM because benefits from the possible control measures do not meet the 8.8 tpd NO X or 34.0 tpd VOC threshold necessary for RACM. These costs may not be in 1999 dollars. (www.mwcog.org/uploads/committee-documents/z1ZZXg20040217144350.pdf ) Comments submitted to the EPA CAIR docket from the Clean Air Task Force et al. , dated March 30, 2004, included costs from the MWCOG analysis.

(II) Cost Effectiveness of CAIR Annual NO X Reductions

Table IV

– 9 provides the average and marginal costs of annual NO X reductions under CAIR for 2009 and 2015. These costs are updated from the NPR figures

— the EPA analyzed the costs of the CAIR using an updated version of IPM (documentation for the IPM update is in the docket). Further, EPA modified the modeling to match the final CAIR strategy (see section IV.A.1 for a description of EPA ’ s CAIR IPM modeling).

CAIR provides for a Compliance Supplement Pool (CSP) of NO X allowances that can be used for compliance with the annual NO X reduction requirements. The CSP is discussed in detail later in this preamble. The EPA used IPM to model marginal costs of CAIR with the CSP. The magnitude of the NO X CSP is relatively small compared to the annual NO X budget, 65 thus the CSP does not significantly impact the marginal costs (see Table IV

– 9). As with SO 2 marginal costs, EPA considered the sensitivity of the NO X marginal cost results to assumptions of higher electric growth and future natural gas prices than the Agency used in the base case, as shown in Table IV

– 9.



### T ABLE 

### IV

– 9.

— E STIMATED 

### C OSTS PER 

### T ON OF 

### A NNUAL 

### NO X 

### C ONTROLLED 

### U NDER 

### CAIR 1

Type of cost effectiveness 2009 2015

Average Cost

— Main Case $500 $700 Marginal Cost

— Main Case 1,300 1,600


### 25210 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

T ABLE 

### IV

– 9.

— E STIMATED 

### C OSTS PER 

### T ON OF 

### A NNUAL 

### NO X 

### C ONTROLLED 

### U NDER 

### CAIR 1



### — Continued

Type of cost effectiveness 2009 2015

Marginal Cost

—With Compliance Supplement Pool (CSP) .................... 1,300 1,600Sensitivity Analysis: Marginal Cost Using Alternate Electricity Growth and Natural Gas Price Assumptions .................. 1,400 1,700

1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

These estimated NO X control costs under CAIR reflect annual EGU NO X caps of 1.5 million tons in 2009 and 1.3 million tons in 2015 within the CAIR annual NO X control region (the 23 States and DC that must make annual reductions). In both the main IPM modeling case and the modeling case that includes the CSP, projected annual NO X emissions in the CAIR region will be about 1.5 million tons in 2009 and 1.3 million tons in 2015. The projected emissions are very similar in both modeling cases because the CSP is relatively small compared to the annual NO X budget.

Average costs shown for 2015 are based on the amount of reductions that would achieve the total difference in projected emissions between the base case conditions and CAIR in the year 2015. These costs are not based on the increment in reductions between 2009 and 2015. (A more detailed description of the final CAIR SO 2 and NO X control requirements is provided later in today ’ s preamble.)

Most of the States subject to today ’ s PM 2.5 control requirements have been subject to the NO X SIP Call requirements. Some sources in these States have installed SCRs, and run them during the ozone season. These sources might comply with the PM 2.5 annual NO X requirements by, at least in part, running the SCR controls for the remaining months of the year. Under these circumstances, the compliance costs for the PM 2.5 SIP requirements are lower.

Table IV

– 10 provides estimated costs per ton of NO X for non-ozone season reductions under CAIR. These figures are updated from the NPR calculations

— the EPA analyzed the costs of the CAIR using an updated version of IPM (documentation for the IPM update is in the docket) and modeled controls on a region that more closely matches the region affected by CAIR.



### T ABLE 

### IV

– 10.

— P REDICTED 

### C OSTS
PER 

### T ON OF 

### N ON 

### -O ZONE 

### S EASON 

### NO X 

### C ONTROLLED 

### U NDER 

### CAIR 1

Type of cost effectiveness 2009 2015

Average Cost .................... $500 $500

1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

The estimated non-ozone season NO X costs, like the annual NO X costs, are on the low end of the cost effectiveness range described in Table IV

– 6. The EPA considers the 2015 and also the 2009 costs to represent highly cost-effective controls.

Environmental Defense reached similar conclusions regarding the cost effectiveness of non-ozone season NO X reductions, as described in their report

‘‘ A Plan for All Seasons: Costs and Benefits of Year-Round NO X Reductions in Eastern States (2002). ’’ As stated in that report, ‘‘ [As Figure 4 shows,] extending NO X reductions throughout the year results in dramatic decreases in the per-ton costs of NO X emission reductions for the 19 NO X SIP Call States. This is because the bulk of the cost for reducing NO X emissions from power plants lies in the capital investment in the control equipment. Once the primary investment has been made, it costs relatively little to continue running the control equipment beyond the summer months required by EPA ’ s NO X SIP Call. ’’ Environmental Defense based these conclusions on analysis conducted by Resources for the Future (RFF). In an RFF paper, ‘‘ CostEffective Reduction of NO X Emissions from Electricity Generation (July 2001), ’’ RFF draws similar conclusions.
(III) NO X Cost Comparison for CAIR Requirements

The EPA believes that selecting as highly cost-effective amounts at the lower end of these average and marginal cost ranges is appropriate for reasons explained above in this section of the preamble.

As discussed above, although in the NO X SIP Call the cost level selected was not at the low end of the reference range of costs, if the NO X SIP Call costs were for annual rather than seasonal controls they would have been lower relative to the other control costs on the reference list which were mostly for annual
programs.

For annual NO X , the range of average cost effectiveness extends broadly, from under $200 to thousands of dollars (Table IV

– 6). The 2015 estimated average costs for CAIR annual NO X control of $700 are consistent with the lower end of this range.

Less information is available for the marginal costs of controls than for average costs. Looking at the available marginal costs (Table IV

– 7), the 2015 CAIR marginal costs for annual NO X controls are at the lower end of the range. The EPA also evaluated the cost effectiveness of the 2009 cap, and concluded that the 2009 requirements are highly cost-effective.
(IV) Cost Effectiveness: Marginal Cost Curves for Annual NO X Control

As with SO 2 controls, EPA also considered the cost effectiveness of alternative stringency levels for NO X control for today ’ s action by examining changes in the marginal cost curve at varying levels of emissions reductions. Figure IV

– 3 shows that the ‘‘ knee ’’ in the 2010 marginal cost effectiveness curve for EGUs

— the point where the cost of controlling a ton of NO X begins to increase at a noticeably higher rate

— appears to occur at over $1,700 per ton of NO X . Although EPA conducted this marginal cost curve analysis based on an initial NO X control phase in 2010, the results would be very similar for 2009, which is the initial NO X phase in the final CAIR. Figure IV

– 4 shows that the ‘‘ knee ’’ in the 2015 marginal cost effectiveness curve for EGUs appears to occur at over $1,700 per ton of NO X . (The EPA based these marginal NO X cost effectiveness curves on the electricity growth and natural gas price assumptions in the main CAIR IPM modeling run. Marginal cost effectiveness curves based on other electric growth and natural gas price assumptions would look different, therefore it would not be appropriate to compare the curves here to the marginal costs based on the IPM modeling sensitivity run that used EIA assumptions.) The EPA used the Technology Retrofitting Updating Model (TRUM), a spreadsheet model based on IPM, for this analysis. These resultsmake clear that this rule is very costeffective because the control level is below the point at which the cost begins to increase at a significantly higher rate.

In this manner, these results corroborate EPA ’ s findings above concerning the cost effectiveness of the emissions reductions. 66

**BILLING CODE 6560**

**– 50** 

**– P** 


### 25211 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

66 EPA is using the knee in the curve analysis solely to show that the required emissions reductions are very cost effective. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. As in the case of SO 2 controls, described above, it should be noted that similar analysis for other source categories may yield different curves.


### 25212 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

67 For both the NO X SIP Call and CAIR, the NO X control costs on the reference lists are generally for annual reductions. The EPA compared the costs of ozone season reductions under the NO X SIP Call, as well as ozone season CAIR NO X reductions, to the annual reduction programs on the reference lists.

68 In the NO X SIP Call EPA used average, not marginal, costs to evaluate cost effectiveness. For the reasons discussed above we are evaluating both average and marginal costs for CAIR.

69 Estimated costs for regionwide CAIR NO X controls during the ozone season are higher than the average and marginal costs for CAIR annual NO X controls. This is because, as noted above, the capital costs of installing NO X control equipment would be largely identical whether the SCR will be operated during the ozone season only or for the entire year. However, the amount of reductions would be less if the control equipment were operated only during the ozone season compared to annual operation.

70 EPA is using the knee in the curve analysis solely to show that the required emissions reductions are very cost effective. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. As in the case of SO 2 controls, described above, it should be noted that similar analysis for other source categories may yield different curves. (V) Cost Effectiveness of Ozone Season NO X Reductions

The CAIR requires ozone season NO X emissions reduction for all States determined to contribute significantly to ozone nonattainment downwind (25 States and the District of Columbia). The EPA used IPM to model average and marginal costs of the ozone season reductions assuming EGU controls. In this modeling case, EPA modeled an ozone season NO X cap for the region affected by CAIR for downwind ozone nonattainment, but did not include the CAIR annual SO 2 or NO X caps. Based on that modeling, Table IV

– 11 provides estimated average and marginal costs of regionwide ozone season NO X reductions for 2009 and 2015. Table IV

– 11 shows the estimated cost effectiveness of today ’ s ozone season NO X control requirements for 8-hour transport SIPs.



### T ABLE 

### IV

– 11.

— E STIMATED 

### C OSTS
PER 

### T ON OF 

### O ZONE 

### S EASON 

### NO X 

### C ONTROLLED 

### U NDER 

### CAIR 1

Type of cost effectiveness 2009 2015

Average Cost .................... $900 $1,800 Marginal Cost ................... 2,400 3,000

1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

These estimated NO X control costs are based on ozone season EGU NO X caps of 0.6 million tons in 2009 and 0.5 million tons in 2015 within the CAIR ozone season NO X control region. Average costs shown for 2015 are based on the amount of reductions that would achieve the total difference in projected emissions between the base case conditions and CAIR in the year 2015. These costs are not based on the increment in reductions between 2009 and 2015. (A more detailed description of the final CAIR SO 2 and NO X control requirements is provided later in today ’ s preamble.)

The EPA believes that selecting as highly cost-effective amounts at the lower end of the average and marginal cost ranges is appropriate for reasons explained above in section IV in this preamble.

In the NO X SIP Call, EPA identified average costs of $2,500 (1999$) (or $2,000 (1990$)) as highly costeffective. 67 The estimated average costs of regionwide ozone season NO X control under CAIR are $1,800 per ton in 2015 and $900 per ton in 2009. Thus, with respect to average costs the controls for the final phase (2015) cap, which are below the $2,500 identified in the NO X SIP Call, are also highly cost-effective, as are those for the 2009 cap. In addition, the estimated average costs of CAIR ozone season NO X control are at the lower end of the reference range of average annual NO X control costs (the reference list of average annual NO X control costs is presented above).

Similarly, the estimated marginal
costs 68 of ozone season CAIR NO X controls are within EPA ’ s reference range of marginal costs, at the lower end of the range (the reference list of marginal annual NO X control costs is presented above). We note that the marginal costs in the reference range are for annual NO X reductions, and would likely be higher for ozone season only programs. Considering both average and marginal costs, the CAIR ozone season control level is highly cost-effective.

For purposes of estimating costs of ozone season control under CAIR, EPA set up this modeling case with CAIR ozone season NO X requirements but without the annual NO X requirements. The Agency believes that the cost of the ozone season CAIR requirements will actually be lower than the costs presented here because interactions will occur between the CAIR annual and ozone season NO X control requirements. 69 In addition, for States in both programs, the same controls achieving annual reductions for PM purposes will achieve ozone season reductions for ozone purposes; this is not reflected in our cost-per-ton estimates.

As with SO 2 controls, and annual NO X controls, EPA also considered the cost effectiveness of alternative stringency levels for CAIR NO X reductions for ozone purposes by examining changes in the marginal cost curve at varying levels of emissions reductions. Figure IV

– 5 shows that the

‘‘ knee ’’ in the 2010 marginal cost effectiveness curve for ozone season NO X reductions from EGUs

— the point where the cost of controlling an ozone season ton of NO X begins to increase at a noticeably higher rate

— appears to occur somewhere between $3,000 and $4,000 per ton of NO X . Although EPA conducted this marginal cost curve analysis based on an initial NO X control phase in 2010 the results would be very similar for 2009, which is the initial NO X phase in the final CAIR. Figure IV

– 6 shows that the ‘‘ knee ’’ in the 2015 marginal cost effectiveness curve for ozone season NO X reductions from EGUs appears to occur somewhere between $3,000 and $4,000 per ton of NO X . The EPA used the Technology Retrofitting Updating Model (TRUM), a spreadsheet model based on the IPM, for this analysis. These results make clear that CAIR NO X reductions for ozone purposes are very cost-effective because the control level is below the point at which the cost begins to increase at a significantly higher rate.

In this manner, these results corroborate EPA ’ s findings above concerning the cost effectiveness of the emissions reductions. 70


### 25213 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations

B. What Other Sources Did EPA Consider When Determining Emission Reduction Requirements?1. Potential Sources of Highly CostEffective Emissions Reductions

In today ’ s rulemaking, EPA determines the amount of regionwide emissions reductions required by determining the amount of emissions reductions that could be achievedthrough the application of highly costeffective controls on certain EGUs. The EPA has reviewed other source categories, but concludes that for purposes of today ’ s rulemaking, there is insufficient information to conclude that highly cost-effective controls are available for other source categories.

a. Mobile and Area Sources

In the NPR (69 FR 4610), EPA explained that ‘‘ it did not identify highly cost-effective controls on mobile or area sources. ’’ No comments were received suggesting that mobile or area sources should be controlled. Therefore, in developing emission reduction requirements, EPA is not assuming any emissions reductions from mobile or

area sources.
b. Non-EGU Boilers and Turbines

The largest single category of stationary source non-EGUs are large non-EGU boilers and turbines. This