ii. Annual Reports Beginning June 1, 2007, all entities that are required to maintain records for batches of fuel must report by facility on an annual basis ( due August 31) information on the total volumes received of each fuel designation as well as the results of all compliance calculations including the following: 333 ° The total volumes transferred of each fuel designation; ° Beginning and ending inventories of each fuel designation; ° In Alaska, for diesel fuel designated as high sulfur NRLM delivered from June 1, 2007 through May 31, 2010 and for diesel fuel designated as 500 ppm sulfur NRLM delivered from June 1, 2010 through May 31, 2014, refiners must report all information required under their individual compliance plan, including the end users to whom each batch of fuel was delivered and the total delivered to each end user for the compliance period; ° Ending with the report due August 31, 2010, calculations showing that the volume of highway diesel fuel distributed from the facility relative to the volume received did not increase since June 1, 2007; ° Ending with the report due August 31, 2010, calculations showing that the volume of highway diesel fuel distributed from the facility relative to new volume received did not increase over the annual compliance period by more than two percent of the total volume of highway diesel fuel received; ° Ending with the report due August 31, 2010, calculations showing that the volume of high sulfur NRLM diesel fuel did not increase by a greater proportion than the volume of heating oil over the annual compliance period ( not applicable in the Northeast/ Mid Atlantic Area or Alaska); ° Calculations showing that the volume of heating oil did not decrease over the annual compliance period, beginning June 1, 2010 ( not applicable in the Northeast/ Mid Atlantic Area or Alaska); and ° From June 1, 2010 through August 1, 2012, calculations showing that the volume of 500 ppm sulfur NR diesel fuel did not increase by a greater proportion than the volume of 500 ppm sulfur LM diesel fuel over the annual compliance period ( not applicable in the Northeast/ Mid Atlantic Area and Alaska.

b. Other Reporting Requirements After the NRLM diesel fuel sulfur requirements begin on June 1, 2007, refiners and importers will be required to submit annual compliance reports for each refinery or import facility. If a refiner produces 15 ppm sulfur or 500 ppm sulfur fuel early under the credit provisions, its annual compliance reporting requirement will begin on June 1 following the beginning of the early fuel production. These reporting requirements will sunset after all flexibility provisions end ( i. e., after May 31, 2014). Annual compliance reports will be due on August 31.

A refiner's or importer's annual compliance report must include the following information for each of its facilities:

° Batch reports for each batch produced or imported providing information regarding volume, designation ( e. g., 500 highway), sulfur level and whether the fuel was dyed and/ or marked. Each batch can only have one designation. Therefore, if a refiner ships 100 gallons of 500 ppm sulfur fuel in 2007 and wants to designate 50 gallons 334 as highway 500 and 50 gallons as NR 500, the refiner must report two separate batches and there must be two PTDs   one for 50 gallons of highway 500 and one for 50 gallons of NR 500).

° Report on the generation, use, transfer and retirement of diesel sulfur credits. Credit transfer information must include the identification of the number of credits obtained from, or transferred to, each entity. Reports must also show the credit balance at the start of the period, and the balance at the end of the period. NRLM or nonroad diesel sulfur credit information is required to be stated separately from highway diesel credit information since the two credit programs are treated separately.

° For a small refiner that elects to produce 15 ppm sulfur NRLM diesel fuel by June 1, 2006 and therefore is eligible for a limited relaxation in its interim small refiner gasoline sulfur standards, the annual reports must also include specific information on gasoline sulfur levels and progress toward highway and NRLM diesel fuel desulfurization.

6. PTDs Refiners, importers, and other parties in the distribution system must provide information on commercial PTDs that identify diesel fuel distributed by use designation and sulfur content; i. e., for use in or motor vehicles, nonroad equipment, locomotive and marine equipment, or nonroad, locomotive, and marine diesel equipment, as appropriate, and the sulfur standard to which the fuel is subject. The PTD must indicate whether the fuel is diesel fuel, heating oil, kerosene, exempt fuel, or other. It must further state whether it is No. 1 or No. 2, dyed or undyed, marked heating oil, marked LM fuel, or unmarked. The specific designations on PTDs will change during the course of the program. For example, the highway designation for 500 ppm sulfur fuel ends after 2010. Where a party delivers or receives a particular load of fuel that has a uniform sulfur content but that has two different designations, the parties must utilize two different PTDs. For example, if, in 2007 a refiner moves 1,000 gallons of 500 ppm sulfur diesel into a pipeline, and the refiner's designation is that half of that product is highway 500 and half is nonroad 500, the parties would utilize one PTD for 500 gallons of highway 500 ppm sulfur diesel fuel and another for 500 gallons of nonroad 500 diesel fuel.

As in other fuels programs, PTDs must accompany each transfer of either title or custody of fuel. However, only custody transfers are relevant to compliance with the designation and tracking requirements and the downgrade limitations, and transfers to retail outlets and wholesale purchaser consumers of fuel by distributors below the truck rack are not covered by the designate and track scheme. Therefore, the PTDs for these non designate and track transfers are somewhat more straightforward. 192 Only one PTD is required for each fuel designation or classification regardless of the number of motor vehicles or the number of diesel powered NRLM equipment that are fueled.

335 We believe this additional information on commercial PTDs is necessary to maintain the integrity of the various grades of diesel fuel in the distribution system. Parties in the system will be better able to identify which type of fuel they are dealing with and more effectively ensure that they are meeting the requirements of today's program. This in turn will help to ensure that misfueling of sulfur sensitive engines does not occur and that the program results in the needed emission reductions.

Today's rule allows the use of product codes to convey the required information, except for transfers to truck carriers, retailers and wholesale purchaser consumers. We believe that more explicit language on PTDs to these parties is necessary since employees of such parties are less likely to be aware of the meaning of product codes. PTDs will not be required for transfers of product into nonroad, locomotive, or marine equipment at retail outlets or wholesale purchaserconsumer facilities with the exception of mobile refuelers. Mobile refuellers are required to provide a separate PTD to their customers for each type of fuel ( e. g., 500 ppm sulfur NRLM diesel fuel, 15 ppm sulfur NRLM diesel fuel, or 15 ppm highway diesel fuel) that they dispense from tanker trucks or other vessels into motor vehicles, nonroad diesel engines or nonroad diesel engine equipment, for each instance when they refuel such equipment at a given location. 192 a. Kerosene and Other Distillates to Reduce Viscosity To ensure that downstream parties can determine the sulfur level of kerosene or other distillates that may be distributed for use for blending into 15 ppm sulfur highway or NRLM diesel fuel, for example, to reduce viscosity in cold weather, we are requiring that PTDs identify distillates specifically distributed for such use as meeting the 15 ppm sulfur standard.

b. Exported Fuel Consistent with other EPA fuel programs, NRLM diesel fuel exported from the U. S. is not required to meet the sulfur standards of today's regulations. For example, where a refiner designates a batch of diesel fuel for export, and can demonstrate through commercial documents that the fuel was exported, such fuel would not be required to comply with the NRLM sulfur standards in today's rule. Product transfer documents accompanying the transfer of custody of the fuel at each point in the distribution system are required to state that the fuel is for export only and may not be used in the United States.

c. Additives Today's rule requires that PTDs for additives for use in NRLM diesel fuel state whether the additive complies with the 15 ppm sulfur standard. Like the highway diesel rule, this program 193 Transmix processors and terminal operators acting as refiners that produce 500 ppm sulfur diesel fuel for sale into the locomotive and marine markets are also subject to the recordkeeping requirements.

336 allows the sale of additives, for use by fuel terminals or other parties in the diesel fuel distribution system, that have a sulfur content greater than 15 ppm under specified conditions.

For additives that have a sulfur content less than 15 ppm, the PTD must state: " The sulfur content of this additive does not exceed 15 ppm." For additives that have a sulfur content greater than 15 ppm, the additive manufacturer's PTD, and PTDs accompanying all subsequent transfers, must provide a warning that the additive's sulfur content exceeds 15 ppm; the maximum sulfur content of the additive; the maximum recommended concentration for use of the additive in diesel fuel ( stated as gallon of additive per gallon of diesel fuel); and the increase in sulfur concentration of the fuel the additive will cause when used at the maximum recommended concentration.

Today's rule contains provisions for aftermarket additives sold to owner/ operators for use in diesel powered nonroad equipment. These provisions are in response to concerns that additives designed for engines not requiring 15 ppm sulfur fuel, such as locomotive or marine engines, could accidentally be introduced into nonroad engines if they had no label stating appropriate use. Beginning June 1, 2010, aftermarket additives for use in nonroad equipment must be accompanied by information that states that the additive complies with the 15 ppm sulfur standard. We believe this information is necessary for end users to determine if an additive is appropriate for use.

7. Record keeping Requirements for Refiners and Importers Refiners and importers of distillate fuel must maintain the following designate and track records for the distillate fuel they produce and/ or import. The specific types of distillate fuel that are subject to these record keeping requirements are described below for the various periods of the program. 193 ° Batch number ( including whether it is an incoming or out going batch for refineries that also handle previously designated fuel); ° Batch designation; ° Volume in gallons; ° Date/ time of day of custody transfer; and ° Name and EPA entity and facility identification number of the facility to which the batch was transferred.

For highway diesel fuel, the records must also identify whether the batch was received or delivered with or without taxes assessed. For NRLM diesel fuel, the records must also identify whether the batch was received or delivered with or without the IRS red dye. For heating oil, the records must indicate whether the batch was received or delivered with or without the fuel marker. 337 From June 1, 2010, through May 31, 2012, the records for LM fuel batches must also indicate whether the batch was received or delivered with or without the fuel marker.

In addition to the designate and track records, refiners and importers must maintain the following records on the highway and NRLM diesel fuel that they produce and/ or import: ° PTDs; ° Sampling and testing results for sulfur content ( for highway and NRLM diesel fuel that is subject to either the 15 ppm or 500 ppm sulfur standards), as well as sampling and testing results that are part of a quality assurance program; ° Sampling and testing results for the cetane index or aromatics content, as well as sampling and testing results for additives; ° Records on credit generation, use, transfer, purchase, or termination, maintained separately for the highway and NRLM diesel fuel credit programs; and ° Records related to individual compliance plans, if applicable, and annual compliance calculations.

a. June 1, 2006 through May 31, 2007 Refiners and importers must maintain the records listed above for each batch of diesel fuel that they designate and transfer custody of during the time period from June 1, 2006 through May 31, 2007, with the following fuel types:

° No. 1 15 ppm sulfur highway diesel fuel; ° No. 2 15 ppm sulfur highway diesel fuel; ° 15 ppm sulfur NRLM diesel fuel; ° No. 1 500 ppm sulfur highway diesel fuel; ° No. 2 500 ppm sulfur highway diesel fuel; or ° 500 ppm sulfur NRLM diesel fuel.

b. June 1, 2007 through May 31, 2010 Refiners and importers must maintain the records listed above for each batch of distillate fuel that they designate and transfer custody of during the time period from June 1, 2007 through May 31, 2010 with the following fuel types:

° No. 1 15 ppm sulfur highway diesel fuel; ° No. 2 15 ppm sulfur highway diesel fuel; ° 15 ppm sulfur NRLM diesel fuel; ° No. 1 500 ppm sulfur highway diesel fuel; ° No. 2 500 ppm sulfur highway diesel fuel; or ° 500 ppm sulfur NRLM diesel fuel; ° High sulfur NRLM diesel fuel; or ° Heating oil. 338 c. June 1, 2010 through May 31, 2012 Refiners and importers must maintain the records listed above for each batch of diesel fuel that they designate and transfer custody of during the time period from June 1, 2010 through May 31, 2012, with the following fuel types:

° 500 ppm sulfur NR diesel fuel; ° 500 ppm sulfur LM diesel fuel; or ° Heating oil.

d. June 1, 2012 through May 31, 2014 Refiners and importers must maintain the records listed above for each batch of distillate fuel that they transfer custody of and designate during the time period from June 1, 2012 through May 31, 2014 with the following fuel types:

° 15 ppm sulfur highway or NRLM diesel fuel; ° 500 ppm sulfur NRLM diesel fuel diesel fuel; or ° Heating oil.

d. June 1, 2014 and Beyond Refiners and importers must maintain the records listed above for each batch of heating oil that they transfer custody of and designate during the time period from June 1, 2014 and beyond.

8. Record keeping Requirements for Distributors Distributors of distillate fuel must maintain the following designate and track records on a facility specific basis for the distillate fuel they distribute. The specific distillate fuel designations that are subject to these record keeping requirements are described below for the various periods of the program.

° Batch number ( including whether it is an incoming or out going batch); ° Batch designation; ° Volume in gallons; ° Date/ time of day of custody transfer; ° Name and EPA entity and facility identification number of the facility from which the fuel batch was received or to which the fuel batch was delivered; ° Beginning and ending inventory volumes on a quarterly basis; and ° Inventory adjustments. 194 After August 1, 2012, LM fuel distributed from terminals must contain a concentration of the marker no greater than 0.1 mg/ L. After October 1, 2012, LM fuel at any location in the fuel distribution system must contain no more than a trace amount of the marker ( 0.1 mg/ L).

339 For highway diesel fuel, the records must also identify whether the batch was received or delivered with or without taxes assessed. For NRLM diesel fuel, the records must also identify whether the batch was received or delivered with or without the IRS red dye. For heating oil, the records must indicate whether the batch was received or delivered with our without the fuel marker. From June 1, 2010, through October 1, 2012, the records must indicate whether LM fuel was received or delivered with or without the fuel marker. 194 In addition to these designate and track records, distributors will be required to maintain records related to their quarterly and annual compliance calculations as well as copies of all PTDs.

If a facility receives fuel from another facility that does not have an EPA facility identification number then that batch of fuel must be designated as 1) heating oil if it is marked, or from 2010 through 2012, LM diesel fuel if the fuel is dyed and marked and is not heating oil 2) highway diesel fuel if taxes have been assessed, and 3) NRLM diesel fuel if the fuel is dyed but not marked.

If a facility delivers fuel to other facilities and that fuel is either 500 ppm sulfur highway diesel fuel on which taxes have been assessed or 500 ppm sulfur NRLM, or LM diesel fuel into which red dye has been added pursuant to IRS requirements, then the facility does not need to maintain separate records for each of the other facilities to which it delivered fuel. Similarly, if a facility delivers batches of marked heating oil to other facilities, then it does not need to maintain separate records for each of the other facilities to which it delivered the marked heating oil. If a facility only receives marked heating oil ( i. e., it does not receive any unmarked heating oil), then it does not need to maintain any heating oil records. Similarly, if a facility only receives highway diesel fuel on which taxes have been assessed or NRLM diesel fuel which has been dyed pursuant to IRS regulations ( i. e., it does not receive any untaxed highway diesel fuel or undyed NRLM diesel fuel), then it does not need to maintain records of the 500 ppm sulfur highway or NRLM diesel fuel that it receives.

a. June 1, 2006 through May 31, 2007 Facilities that receive No. 2 15 ppm sulfur highway diesel fuel and distribute any No. 2 500 ppm sulfur highway diesel fuel, must maintain records for each batch of diesel fuel with the following designations that they receive or deliver during the time period from June 1, 2006 through May31, 2007:

° No. 1 15 ppm sulfur highway diesel fuel; ° No. 2 15 ppm sulfur highway diesel fuel; ° No. 2 500 ppm sulfur highway diesel fuel; and 340 ° 500 ppm sulfur NRLM diesel fuel.

b. June 1, 2007 through May31, 2010 All facilities must maintain records for each batch of diesel fuel or heating oil with the following designations for which they receive or transfer custody during the time period from June 1, 2007 through May31, 2010:

° No. 1 15 ppm sulfur highway diesel fuel; ° No. 2 15 ppm sulfur highway diesel fuel; ° No. 1 500 ppm sulfur highway diesel fuel; ° No. 2 500 ppm sulfur highway diesel fuel; ° 500 ppm sulfur NRLM diesel fuel; ° 15 ppm sulfur NRLM diesel fuel; ° High sulfur NRLM diesel fuel; and ° Heating oil.

c. June 1, 2010 through May31, 2012 All facilities must maintain records for each batch of diesel fuel or heating oil with the following designations for which they receive or transfer custody during the time period from June 1, 2007 through May 31, 2012. This requirement does not apply to facilities located in the Northeast/ Mid Atlantic Area or Alaska.

° 500 ppm sulfur NR diesel fuel; ° 500 ppm sulfur LM diesel fuel; or ° Heating oil.

c. June 1, 2012 through May 31, 2014 Facilities that receive unmarked fuel designated as heating oil, must maintain records for each batch of diesel fuel with the following designations that they receive or deliver during the time period from June 1, 2012 through May 31, 2014. This requirement does not apply to facilities located in Alaska or the Northeast/ Mid Atlantic Area unless they deliver marked heating oil to facilities outside of these areas.

° 500 ppm sulfur NRLM diesel fuel; and ° Heating oil. 341 d. June 1, 2014 and Beyond Facilities that receive unmarked fuel designated as heating oil must maintain records for each batch of diesel fuel with the following designations that they receive or deliver during the time period beginning June 1, 2014. This requirement does not apply to facilities located in Alaska or the Northeast/ Mid Atlantic Area unless they deliver marked heating oil to facilities outside of these areas.

° 500 ppm sulfur LM diesel fuel, and ° Heating oil.

9. Record keeping Requirements for End Users Today's program also contains certain record keeping provisions for end users. From June 1, 2007 through October 1, 2010, end users that receive any batch of high sulfur NRLM in Alaska must maintain records of each batch of fuel received for use in NRLM equipment unless otherwise allowed by EPA. From June 1, 2010 through October 1, 2012, end users that receive any batch of 500 ppm sulfur NR in Alaska must maintain records of each batch of fuel received for use in NR equipment unless otherwise allowed by EPA. In addition, from June 1, 2012 through October 1, 2014, end users that receive any batch of 500 ppm sulfur NRLM in Alaska must maintain records of each batch of fuel received for use in NRLM equipment unless otherwise allowed by EPA.

10. Record Retention We are adopting a retention period of five years for all records required to be kept under today's rule. This is the same period of time required in other fuels rules, and it coincides with the applicable statute of limitations. We believe that most parties in the distribution system would maintain some or all of these records for this length of time even without the requirement.

This retention period applies to PTDs, records required under the designate and track provisions, records of any test results performed by any regulated party for quality assurance purposes or otherwise ( whether or not such testing was required by this rule), along with supporting documentation such as date of sampling and testing, batch number, tank number, and volume of product. Business records regarding actions taken in response to any violations discovered must also be maintained for five years.

All records that are required to be maintained by refiners or importers participating in the generation or use of credits, hardship options ( or by importers of diesel fuel produced by a foreign refiner approved for the temporary compliance option or a hardship option), including small refiner options, are also covered by the retention period. 195 See section 80.5 ( penalties for fuels violations); section 80.23 ( liability for lead violations);

section 80.28 ( liability for gasoline volatility violations); section 80.30 ( liability for highway diesel violations); section 80.79 ( liability for violation of RFG prohibited acts); section 80.80 ( penalties for RFG/ CG violations); section 80.395 ( liability for gasoline sulfur violations); section 80.405 ( penalties for gasoline sulfur regulations).; and section 80.610 614 ( prohibited acts, liability for violations, and penalties for highway diesel sulfur regulations.

196 Today's rule, in 40 CFR § 80.610, provides that no person shall, inter alia, " dispense,

supply, offer for supply, store or transport . . ." fuel not in compliance with applicable standards and requirements starting on a certain date. These prohibitions apply at downstream locations such as retail outlets, wholesale purchaser consumer facilities as well as end user locations. The act of storage or transport refers to storage or transport in fuel storage tanks from which fuel is dispensed into motor vehicles or NRLM engines or equipment. It does not refer to storing or transporting the fuel that is in the motor vehicle propulsion tank or other tank that is incorporated in the NRLM equipment for the purpose of supplying the engine with fuel. While the prohibition against dispensing inappropriate fuels does apply as of the applicable date, the motor vehicle or NRLM engine or equipment may continue to burn any fuel in the motor vehicle fuel tank or NRLM equipment fuel tank that was properly dispensed into such tank .

342 H. Liability and Penalty Provisions for Noncompliance 1. General The liability and penalty provisions of the today's NRLM diesel sulfur rule are very similar to the liability and penalty provisions found in the highway diesel sulfur rule, the gasoline sulfur rule, the reformulated gasoline rule and other EPA fuels regulations. 195 Regulated parties are subject to prohibitions which are typical in EPA fuels regulations, such as prohibitions on selling or distributing fuel that does not comply with the applicable standard, and causing others to commit prohibited acts. For example, liability will also arise under the NRLM diesel rule for violating certain prohibited acts and requirements, such as: distributing or dispensing NR diesel fuel not meeting the 15 ppm sulfur standard for use in model year 2011 or later nonroad equipment ( and after Dec 1, 2014 into any nonroad diesel equipment); distributing or dispensing diesel fuel not meeting the 500 ppm sulfur standard for locomotive and marine engines; distributing fuel containing the marker for use in engines that require the use of fuel that does not contain the marker; prohibitions and requirements under the designate and track provisions in today's rule, including specific prohibitions and requirements regarding fuel produced or distributed in the Northeast/ Mid Atlantic Area or in Alaska. 196 Small refiners and refiners using credits can produce high sulfur NRLM when NRLM would otherwise be required to meet a 500 ppm sulfur standard, and can produce 500 ppm sulfur 197 An additional type of liability, vicarious liability, is also imposed on branded refiners under today's rule.

343 NR or LM diesel fuel when nonroad or LM diesel fuel would otherwise be required to meet a 15 ppm sulfur standard. A refiner that produces fuel under the small refiner and credit provisions would be in violation unless they can demonstrate that they meet the definition of a small refiner or have sufficient credits for the volume of fuel produced. All regulated parties will be liable for a failure to meet certain requirements, such as the record keeping, reporting, or PTD requirements, or causing others to fail to meet such requirements.

Under today's rule, the party in the diesel fuel distribution system that controls the facility where a violation occurred, and other parties in that fuel distribution system ( such as the refiner, reseller, and distributor), will be presumed to be liable for the violation. 197 As in the Tier 2 gasoline sulfur rule and the highway diesel fuel rule, today's rule explicitly prohibits causing another person to commit a prohibited act or causing non conforming diesel fuel to be in the distribution system. Non conforming fuels include: 1) diesel fuel with sulfur content above 15 ppm incorrectly represented as appropriate for model year 2011 or later nonroad equipment or other engines requiring 15 ppm fuel; 2) diesel fuel with sulfur content above 500 ppm incorrectly represented as appropriate for nonroad equipment or locomotives or marine engines after the applicable date for the 500 ppm sulfur standard for these pieces of equipment; 3) heating oil that is required to contain the marker which does not, LM fuel which is required to contain the marker which does not, or other fuels that are required to be free of the marker in which the marker is present; 4) fuel designated or labeled as 500 ppm sulfur highway diesel fuel above and beyond the volume balance limitations; 5) fuel designated or labeled as NRLM above and beyond the volume balance limitations; or 6) fuels otherwise not complying with the requirements of this rule. Parties outside the diesel fuel distribution system, such as diesel additive manufacturers and distributors, are also subject to liability for those diesel rule violations which could have been caused by their conduct.

Today's rule also provides affirmative defenses for each party presumed liable for a violation, and all presumptions of liability are rebuttable. In general, in order to rebut the presumption of liability, parties will be required to establish that: 1) the party did not cause the violation; 2) PTD( s) exist which establish that the fuel or diesel additive was in compliance while under the party's control; and 3) the party conducted a quality assurance sampling and testing program. As part of their affirmative defense diesel fuel refiners or importers, diesel fuel additive manufacturers, and blenders of high sulfur additives into diesel fuel, will also be required to provide test results establishing the conformity of the product prior to leaving that party's control. Blenders of static dissipater additives have alternative defense provisions as discussed in section V. C. Branded refiners have additional affirmative defense elements to establish. The defenses under the nonroad diesel sulfur rule are similar to those available to parties for violations of the highway diesel sulfur, reformulated gasoline, gasoline volatility, and the gasoline sulfur regulations. Today's rule also clarifies that parent corporations are liable for violations of subsidiaries, in a manner consistent with the gasoline sulfur rule and the highway diesel sulfur rule. Finally, the 198 This limit is amended periodically pursuant to Congressional authority to change maximum civil penalties to account for inflation.

199 At downstream locations the violation will occur if EPA's test result show a sulfur content of greater than 17 ppm, which takes into account the two ppm adjustment factor for testing reproducibility for downstream parties.

344 NRLM diesel sulfur rule mirrors the gasoline sulfur rule and the highway diesel sulfur rule by clarifying that each partner to a joint venture will be jointly and severally liable for the violations at the joint venture facility or by the joint venture operation.

As is the case with the other EPA fuels regulations, today's rule will apply the provisions of section 211( d)( 1) of the Clean Air Act ( Act) for the collection of penalties. These penalty provisions currently subject any person that violates any requirement or prohibition of the diesel sulfur rule to a civil penalty of up to $ 32,500 for every day of each such violation and the amount of economic benefit or savings resulting from the violation. 198 A violation of a NRLM diesel sulfur standard will constitute a separate day of violation for each day the diesel fuel giving rise to the violation remains in the fuel distribution system. Under today's regulation, the length of time the diesel fuel in question remains in the distribution system is deemed to be twenty five days unless there is evidence that the fuel remained in its distribution system a lesser or greater amount of time. This is the same time presumption that is incorporated in the RFG, gasoline sulfur and highway diesel sulfur rules. The penalty provisions in today rule are also be similar to the penalty provisions for violations of these regulations.

EPA has included in today's rule two prohibitions for " causing" violations: 1) causing another to commit a violation; and 2) causing non complying diesel fuel to be in the distribution system. These causation prohibitions are like similar prohibitions included in the gasoline sulfur and the highway diesel sulfur regulations, and, as discussed in the preamble to those rules, EPA believes they are consistent with EPA's implementation of prior motor vehicle fuel regulations. See the liability discussion in the preamble to the gasoline sulfur final rule, at 65 FR 6812 et seq.

The prohibition against causing another to commit a violation will apply where one party's violation is caused by the actions of another party. For example, EPA may conduct an inspection of a terminal and discover that the terminal is offering for sale nonroad diesel fuel designated as complying with the 15 ppm sulfur standard, while the fuel, in fact, had an actual sulfur content greater than the standard. 199 In this scenario, parties in the fuel distribution system, as well as parties in the distribution system of any diesel additive that had been blended into the fuel, will be presumed liable for causing the terminal to be in violation. Each party will have the right to present an affirmative defense to rebut this presumption.

The prohibition against causing non compliant diesel fuel to be in the distribution system will apply, for example, if a refiner transfers non compliant diesel fuel to a pipeline. This prohibition could encompass situations where evidence shows high sulfur diesel fuel was 345 transferred from an upstream party in the distribution system, but EPA may not have test results to establish that parties downstream also violated a prohibited act with this fuel.

The Agency expects to enforce the liability scheme of the NRLM diesel sulfur rule in the same manner that we have enforced the similar liability schemes in our prior fuels regulations. As in other fuels programs, we will attempt to identify the party most responsible for causing the violation, recognizing that party should primarily be liable for penalties for the violation.

2. What are the Liability Provisions for Additive Manufacturers and Distributors, and Parties That Blend Additives into Diesel Fuel?

a. General The final highway diesel rule permits the blending of diesel fuel additives with sulfur content in excess of 15 ppm into 15 ppm highway diesel fuel under limited circumstances. As more fully discussed earlier in this preamble, this rule also permits downstream parties to blend fuel additives having a sulfur content exceeding 15 ppm into 15 ppm nonroad diesel, provided that: 1) the blending of the additive does not cause the diesel fuel's sulfur content to exceed the 15 ppm sulfur standard; 2) the additive is added in an amount no greater than one volume percent of the blended product; and 3) the downstream party obtained from its additive supplier a product transfer document (" PTD") with the additive's sulfur content and the recommended treatment rate, and that it complied with such treatment rate. As discussed in section V. C, today's rule includes alternate affirmative defense requirements for blenders of S D additives that can contribute a maximum of 0.050 ppm to the sulfur content of finished fuel subject to the 15 ppm sulfur standard. Today's rule also implements these same alternate defense requirements regarding the blending of such additives into 15 ppm highway diesel fuel.

Since today's rule permits the limited use in nonroad diesel fuel of additives with high sulfur content, the Agency believes it might be more likely that a diesel fuel sulfur violation could be caused by the use of high sulfur additives. This could result from the additive manufacturer's misrepresentation or inaccurate statement of the additive's sulfur content or recommended treat rate on the additive's PTD, or an additive distributor's contamination of low sulfur additives with high sulfur additives during transportation. The increased probability that parties in the diesel additive distribution system could cause a violation of the sulfur standard warrants the imposition by the Agency of increased liability for such parties. Therefore, today's rule, like the final highway diesel rule, explicitly makes parties in the diesel additive distribution system liable for the sale of nonconforming diesel fuel additives, even if such additives have not yet been blended into diesel fuel. In addition, today's rule imposes presumptive liability on parties in the additive distribution system if diesel fuel into which the additive has been blended is determined to have a sulfur level in excess of its permitted concentration. This presumptive liability will differ depending on whether the blended additive was designated as meeting the 15 ppm sulfur standard ( a " 15 ppm additive") or designated as a greater than 15 ppm sulfur additive ( a " high sulfur additive"), as discussed below. 346 b. Liability When the Additive Is Designated as Complying with the 15 ppm Sulfur Standard Additives blended into diesel fuel downstream of the refinery are required to have a sulfur content no greater than 15 ppm, and be accompanied by PTD( s) accurately identifying them as complying with the 15 ppm sulfur standard, with the sole exception of diesel additives blended into nonroad diesel fuel at a concentration no greater than one percent by volume of the blended fuel.

All parties in the fuel and additive distribution systems will be subject to presumptive liability if the blended fuel exceeds the sulfur standard. The two ppm downstream adjustment will apply when EPA tests the fuel subject to the 15 ppm sulfur standard. Low sulfur additives present a less significant threat to diesel fuel sulfur compliance than would occur with the use of additives designated as possibly exceeding 15 ppm sulfur. Thus, parties in the additive distribution system of the low sulfur additive could rebut the presumption of liability by showing the following: 1) additive distributors will only be required to produce PTDs stating that the additive complies with the 15 ppm sulfur standard; 2) additive manufacturers are also be required to produce PTDs accurately indicating compliance with the regulatory requirements, as well as producing test results, or retained samples on which tests could be run, establishing the additive's compliance with the 15 ppm sulfur standard prior to leaving the manufacturer's control. Once they meet their defense to presumptive liability, these additive system parties will only be held responsible for the diesel fuel non conformity in situations in which EPA can establish that the party actually caused the violation.

Under today's rule, parties in the diesel fuel distribution system will have the typical affirmative defenses of other fuels rules. For parties blending an additive into their diesel fuel, the requirement to maintain PTDs showing that the product complied with the regulatory standards will necessarily include PTDs for the additive that was used, affirming the compliance of the additive and the fuel.

c. Liability When the Additive Is Designated as Having a Possible Sulfur Content Greater than 15 ppm Under today's rule, a nonroad diesel fuel additive will be permitted to have a maximum sulfur content above 15 ppm if the blended fuel continues to meet the 15 ppm standard and the additive is used at a concentration no greater than one volume percent of the blended fuel. However, if nonroad diesel fuel containing that additive is found by EPA to have high sulfur content, then all the parties in both the additive and the fuel distribution chains will be presumed liable for causing the nonroad diesel fuel violation.

Since this type of high sulfur additive presents a much greater probability of causing diesel fuel non compliance, parties in the additive's distribution system will have to satisfy an additional element to establish an affirmative defense. In addition to the elements of an affirmative defense described above, parties in the additive distribution system for such a high sulfur additive will also 347 be required to establish that they did not cause the violation, an element of an affirmative defense that is typically required in EPA fuel programs to rebut presumptive liability.

Parties in the diesel fuel distribution system will essentially have to establish the same affirmative elements as in other fuels rules, with an addition comparable to the highway diesel rule. Blenders of high sulfur additives into 15 ppm sulfur nonroad diesel fuel, will have to establish a more rigorous quality control program than will exist without the addition of such a high sulfur additive. For additives other than static dissipater additives, to establish a defense to presumptive liability, the Agency has adopted the proposal to require test results establishing that the blended fuel was in compliance with the 15 ppm sulfur standard after being blended with the high sulfur additive. This additional defense element will be required as a safeguard to ensure nonroad diesel fuel compliance, since the blender has voluntarily chosen to use an additive which increases the risk of diesel fuel non compliance.

An exception to this defense element is made for blenders of static dissipater additives, that are allowed by today's rule to contribute no more than 0.05 ppm to the sulfur content of a finished fuel subject to the 15 ppm sulfur standard. As discussed in section V. C. 5, blenders of such additives may rely on volume accounting reconciliation records in lieu of the requirement to sample and test each batch of fuel subject to the 15 ppm sulfur standard after the addition of an additive that exceeds the 15 ppm sulfur standard. Today's rule also implements these same alternate defense requirements regarding the blending of such additives into 15 ppm highway diesel fuel.

I. How Will Compliance with the Sulfur Standards Be Determined?

Today's rule provides that compliance with the sulfur standards and use requirements under today's rule can be determined by evaluating the designate and track records ( discussed in section IV. D.) and other records, such as PTDs; by evaluating compliance with the fuel marker requirements discussed in section IV. D and V. E; and by sampling fuel and testing for sulfur content. Today's rule includes a requirement for refiners and importers to measure the sulfur content of every batch of NRLM fuel designated under the rule, using a testing methodology approved under the provisions discussed in section V. H of this preamble. In general, downstream parties must conduct only periodic sampling and testing as an element of a defense to presumptive liability ( retailers are exempt from sampling and testing). Today's rule further provides that in determining compliance, any evidence from any source or location can be used to establish the diesel fuel sulfur level, provided that such evidence is relevant to whether the sulfur level would have met the applicable standard had compliance been determined using an approved test methodology. While the use of a non approved test method might produce results relevant to determining sulfur content, this does not remove any liability for failing to conduct required batch testing using an approved test method. This is consistent with the approach taken under the gasoline sulfur rule and the highway diesel sulfur rule.

For example, the Agency might not have sulfur results derived from an approved test method for diesel fuel sold by a terminal, yet the terminal's own test results, based on testing using 348 methods other than those approved under the regulations, could reliably show a violation of the sulfur standard. Under today's rule, evidence from the non approved test method could be used to establish the diesel fuel's sulfur level that would have resulted if an approved test method had been conducted. This type of evidence is available for use by either the EPA or the regulated party, and could be used to show either compliance or noncompliance. Similarly, absent the existence of sulfur test results using an approved method, commercial documents asserting the sulfur level of diesel fuel or additive could be used as some evidence of what the sulfur level of the fuel would be if the product would have been tested using an approved method.

The Agency believes that the same statutory authority for EPA to adopt the gasoline sulfur rule's evidentiary provisions, Clean Air Act section 211( c), provides appropriate authority for the evidentiary provisions of today's diesel sulfur rule. For a fuller explanation of this statutory authority, see the gasoline sulfur final rule preamble, 65 FR 6815, February 10, 2000. 349 VI. Program Costs and Benefits In this section, we present the projected cost impacts and cost effectiveness of the nonroad Tier 4 emission standards and fuel sulfur requirements. We also present a benefit cost analysis and an economic impact analysis. The benefit cost analysis explores the net yearly economic benefits to society of the reduction in mobile source emissions likely to be achieved by this rulemaking. The economic impact analysis explores how the costs of the rule will likely be shared across the manufacturers and users of the engines, equipment and fuel that would be affected by the standards.

We revised our cost and benefit analysis to reflect the comments we received on our analysis. The fuel related costs have been updated to reflect information received from refiners as part of EPA's highway diesel fuel program, comments received on the nonroad NPRM, as well as more recent information available on future energy costs and the cost of advanced desulfurization technologies. The engine and equipment related costs were revised to reflect additional R& D costs associated with tailoring R& D to each particular engine line and to accommodate changes in the final emission control requirements, particularly with regard to engines above 750 hp. These costs also now presented in 2002 instead of 2001 dollars. With regard to the benefits analysis, we have updated our methods consistent with Science Advisory Board ( SAB) advice as specified in RIA chapter 9. Finally, we adjusted the economic impact analysis to reflect the revised cost inputs and to explicitly model the impacts on the locomotive and marine intermediate market sectors.

The results detailed below show that this rule would be highly beneficial to society, with net present value benefits through 2036 of $ 805 billion using a 3 percent discount rate and $ 352 billion using a 7 percent discount rate, compared to a net present value of social cost of about $ 27 billion using a 3 percent discount rate and $ 14 billion using a 7 percent discount rate. The impact of these costs on society should be minimal, with the prices of goods and services produced using equipment and fuel affected by standards being expected to increase about 0.1 percent.

Further information on these and other aspects of the economic impacts of this emission control program are summarized in the following sections and are presented in more detail in the Final RIA for this rulemaking.

A. Refining and Distribution Costs Meeting the 500 and 15 ppm sulfur caps will generally require that refiners add hydrotreating equipment and possibly new or expanded hydrogen and sulfur plants in their refineries. We have estimated the cost of building and operating this equipment using the same basic methodology which was described in the NPRM. We have updated that analysis with new information obtained from the vendors of advanced desulfurization technology, to better reflect current crude oil properties and refinery configurations, as well as future hydrogen costs. We have also incorporated information received from refiners regarding their plans to produce 15 ppm highway diesel fuel from 2006 2010. Finally, we incorporated the 15 ppm cap on locomotive and 350 marine fuel in 2012, as well as improving our analysis of the impact of this cap on costs incurred in the distribution system.

The costs to provide NRLM fuel under the two step fuel program are summarized in Table VI. A 1 below. All of the following costs estimates are in 2002 dollars. Capital investments have been amortized at 7 percent per annum before taxes. These estimates do not include costs associated with fuel sulfur testing, labeling, reporting or record keeping, which we believe will be small relative to those associated with refining, distribution and lubricity additives. A more detailed description of the costs associated with this final rule is presented in the Final RIA.

Table VI. A 1.   Cost of Providing NRLM Diesel Fuel ( cents per gallon of affected fuel)

NRLM Diesel Fuel Years Affected Fuel Volume ( million gallons per year) a Refining Distribution ( and Lubricity) Total 500 ppm 2007 2010 11,860 1.9 0.2 2.1 2010 2012 3,589 2.7 0.6 3.3 2012 2014 715 2.9 0.6 3.5 15 ppm 2010 2012 8,145 5.0 0.8 5.8 2012 2014 12,068 5.6 0.8 6.4 2014 + 13,399 5.8 1.2 7.0 Notes: a Volumes shown are for first full year in each period ( 2008, 2011, 2013, and 2015).

The costs shown ( and all of the costs described in the rest of this section) apply to the 74 percent of current NRLM fuel that currently contains more than 500 ppm sulfur ( hereafter referred to as the affected volume).

In 2014, the affected volume of NRLM fuel is 14.6 billion gallons out of total NRLM fuel volume of 19.7 billion gallons. The other 5.1 billion gallons of NRLM fuel is currently spillover from fuel certified to the highway diesel fuel standards. We expect this to continue under the 2007 highway diesel fuel program. Thus, 26 percent of NRLM fuel will already meet at least a 500 ppm sulfur cap by 2007 and a 15 ppm cap by 2010 and will not be affected by today's rule. The costs and benefits of desulfurizing this highway fuel which spills over into the non highway markets was included in our cost estimates for the 2007 highway diesel fuel rule.

The estimated cost of the first step of the NRLM fuel program is slightly less than that projected in the NPRM ( cents per gallon). However, we have increased our estimated cost of the second step significantly in response to comments. These comments and the changes to our cost estimates are discussed in more detail in the next two sections. The combined cost for both steps 351 is therefore somewhat higher than expected in the NPRM, but nevertheless consistent with projections for the cost of 15 ppm highway diesel fuel.

We expect that the increased cost of refining and distributing 500 ppm NRLM fuel will be completely offset by reductions in maintenance costs, while those for 15 ppm NRLM fuel will be significantly offset. These savings will apply to all diesel engines in the fleet due to the reduced fuel sulfur content, not just new engines. Refer to section V. B for a more complete discussion on the projected maintenance savings associated with lower sulfur fuels.

1. Refining Costs Methodology: We followed the same process that we used in the NPRM to project refining costs, though we have broken down the description into five steps instead of four.

First, we estimate the total volume of NRLM fuel which must be desulfurized during each step of the program, as well as each refinery's future total production of distillate fuel. Current and future demand for all distillate fuels except diesel fuel for land based equipment were based on estimates from the Energy Information Administration's ( EIA) Fuel Oil and Kerosene Survey ( FOKS) for 2001 and the 2003 Annual Energy Outlook ( AEO). EPA's NONROAD emission model was used to estimate both current and future fuel consumption by land based nonroad equipment to ensure the consistent treatment of both the costs and benefits associated with this rule. Table VI. A 2 shows our projections of the volumes of fuel affected by today's rule. These volumes exclude NRLM fuel expected to be certified to highway diesel fuel sulfur caps prior to the implementation of this rule. They also exclude distillate fuel meeting a 500 ppm cap which is produced during distribution from highway diesel fuel, jet fuel, etc.

Table VI. A 2.   Volume of NRLM Fuel Affected by Today's Rule ( billion gallons per year)

Nonroad Locomotive and Marine Total 500 ppm 15 ppm 500 ppm 15 ppm 500 ppm 15 ppm 2008 8,406 0 3,454 0 11,860 0 2011 614 8,145 2,975 0 3,589 8,145 2013 468 8,671 247 3,395 715 12,066 2015 0 10,539 2,860 0 13,399 This marks a change from the proposal, where all distillate fuel volumes were based on EIA FOKS and AEO estimates. Commenters pointed out that this approach underestimated fuelrelated costs relative to emission reductions and monetized benefits, since the NONROAD fuel volumes used to estimate the latter were larger. We in fact had acknowledged this inconsistency in the proposal and had said we would address it in the final rule. Our approach to address the 200 The year 2014 represents a mid point between the initial year of today's fuel program and the end of the expected life of desulfurization equipment ( roughly 15 years).

201 Under EPA's 2007 highway diesel program, refiners are required to submit their production plans for highway diesel fuel for 2006 2010. The first of these reports were due during the summer of 2003. EPA published a summary of the results this past fall. We consider these reports to provide a more accurate projection of individual refinery plans than our projections made during the highway fuel FRM.

The latter was based on cost minimization using our refinery specific desulfurization refinery model.

352 inconsistency was to utilize the land based nonroad fuel volumes estimated by the NONROAD model for both the costs and monetized benefits. However, we also conducted a sensitivity analysis whereby both emissions and costs were estimated using EIA estimates of fuel demand by land based nonroad equipment. The results of that analysis are discussed in chapter VII of the Final RIA.

We made one other revision to the volume of diesel fuel affected by this rule. In analyzing the impact of the 2007 highway diesel fuel program for the NPRM analysis, we estimated that 4.4 percent of 15 ppm highway diesel fuel would be contaminated during shipment and not available for sale as 15 ppm highway fuel. This increased the volume of 15 ppm highway fuel which had to be produced at refineries before accounting for the production of additional 500 and 15 ppm NRLM fuel in response to the NRLM fuel program. Due to comments made on the NRPM ( discussed in section VI. A. 3. below), we have improved our analysis to track the disposition of this contaminated 15 ppm fuel. Much of this contaminated fuel can be sold as 500 ppm NRLM from 2007 2014 and as L& M fuel thereafter. Thus, the contaminated 15 ppm fuel reduces the volume of 500 and 15 ppm NRLM fuel which must be produced at refineries.

Second, total distillate production by individual refineries were based on their actual production volumes in 2002, as reported to EIA. This represents a minor revision to the NPRM analysis, which utilized actual refiner production in 2000. The number of refineries needing to produce 500 ppm and 15 ppm diesel fuel under today's final rule was based on the projected diesel fuel and heating oil demand in 2014.200 To be consistent, the 2002 distillate production volumes of individual refiners were increased to 2014 levels using EIA projections of growth in total distillate production by domestic refiners.

Third, we estimated the cost to desulfurize diesel fuel to both 500 ppm and 15 ppm for each domestic refinery. This considered both the volume of diesel fuel being produced and its composition ( e. g., percentage of straight run, light cycle oil, etc.). Estimates of the volumes of diesel fuel already being desulfurized to meet the highway diesel fuel standards in 2006 2010 prior to the implementation of this final rule were based on refiners' pre compliance reports. 201 This marks a change from the NPRM analysis, where we assumed that refiners would continue to produce their current mix of highway and high sulfur diesel fuel. While many refiners indicated that their plans were preliminary and subject to change, we consider these projections to be more 353 probable than assuming that current producers of diesel fuel will make no change to their product mix in complying with the highway rule. Meeting the 15 ppm highway diesel fuel cap will require significant investment, but some refiners will face more than others. Some refiners will be able to revamp their current hydrotreater, while others will need to build an entirely new unit. Some refiners will be able to expand their production of highway fuel at little incremental cost, while others will be able to reduce their investment substantially by reducing their production volume. Use of refiners' own projections, as opposed to our own cost methodology assumptions, allows us to incorporate as much refinery specific information as is currently possible.

In projecting desulfurization costs, we updated a number of the inputs to our cost estimation methodology. We increased natural gas and utility costs to reflect those projected in EIA's 2003 AEO. The NPRM analysis utilized projections from 2002 AEO. Forecasted natural gas costs in 2003 AEO are considerable higher than in 2002 AEO, though still lower than current market prices. In response to comments, we also increased the factor for off site capital costs to better reflect the cost of sulfur plant expansions. The NPRM analysis utilized an off site factor developed in support of the Tier 2 gasoline and 2007 highway diesel fuel programs, where the amount of sulfur removed per gallon was a fraction of that occurring here with NRLM fuel. We also continued to update our cost estimates for advanced desulfurization technologies, as these technologies continue their evolution. As discussed in Section IV, the latest information concerning Process Dynamics's IsoTherming process indicate somewhat higher costs than earlier estimates. We also reduced our projection of the penetration of these advanced technologies in 2010 from 80 to 60 percent.

Fourth, we estimated which refineries will likely find it difficult to stay in the heating oil market after the implementation of the NRLM sulfur standards, due to their location relative to major pipelines and the size of the heating oil market in their area. Those not located in major heating oil markets and not connected to pipelines serving these areas were projected to have to meet the 500 and 15 ppm caps in 2007 and 2010, respectively.

Fifth, we estimated which of the remaining refineries would likely produce NLRM fuel under today's program. As was done in the proposal, we assumed that those refineries with the lowest projected compliance costs would be the most likely to produce the required fuel until demand was met. Inter PADD transfers of fuel between PADD 3 and PADD 1 were not constrained. PADD 3 refineries were also assumed to supply PADD 2 with 15 ppm NRLM fuel once all PADD 2 refineries were producing 15 ppm distillate fuel. We also assumed that domestic refineries would preferentially supply the lowest sulfur fuels compared to imports. Thus, imports of 15 and 500 ppm NRLM fuel were only assumed after all refineries in a PADD were projected to produce either 15 or 500 ppm fuel, respectively. The small refiner provisions included in today's NRLM fuel program were considered, as these provisions temporarily reduce the volume of 500 and 15 ppm fuel required to be produced in 2007 and 2010, respectively. This portion of the methodology was the same as that used in the NRPM analysis. 354 Results: Based on EIA data, in 2002 114 refineries produced highway diesel fuel and 102 refineries produce high sulfur diesel fuel or heating oil. Based on refiners' pre compliance reports, we project that 100 refineries will produce 15 ppm highway diesel fuel; 96 refineries starting in 2006 and 4 in 2010. Of these 100 refineries, 96 currently produce some volume of highway diesel fuel, while 4 refineries currently only produce high sulfur distillate fuel. Also, 18 refineries will cease to produce highway diesel fuel and shift to producing solely high sulfur distillate fuel. This will leave a total of 92 refineries still producing high sulfur distillate after full implementation of the 2007 highway diesel fuel program.

The number of these 92 domestic refineries expected to produce either 15 or 500 ppm NRLM diesel fuel in response to today's rule is summarized in Table VI. A 3.

Table VI. A 3.   Refineries Projected to Produce NRLM Diesel Fuel Under This Final Rule Year of Program 500 ppm NRLM Diesel Fuel 15 ppm NRLM Diesel Fuel All Refineries Small Refineries All Refineries Small Refineries 2007 2010 36 0 0 0 2010 2012 26 13 32 2 2012 2014 15 13 47 2 2014+ 0 0 63 15 During the four periods shown in table VI. A 3, two roughly parallel sets of standards become effective. For non small refiners, the 500 ppm NRLM fuel cap starts in 2007, followed by the 15 ppm nonroad fuel cap in 2010, in turn followed by the 15 ppm L& M fuel cap in 2012. For small refiners, the 500 ppm NRLM fuel cap starts in 2010, followed by the 15 ppm nonroad NRLM fuel cap in 2014. As shown, beginning in 2014, 63 refineries are projected to be affected by today's final rule. After complete implementation of today's rule, 29 refineries are expected to be able to produce high sulfur heating oil, some as their entire distillate production, others along with 15 ppm fuel. The number of refineries estimated to be affected by today's rule is one more than that projected in the NPRM. There, we estimated that 62 refineries would have to produce either 15 or 500 ppm NRLM fuel in 2014 and beyond.

We project that the capital cost involved to meet the 2007 500 ppm sulfur cap will be $ 310 million. This represents about $ 10 million for each of the 30 refineries building a new hydrotreater. Six refineries are expected to produce 500 ppm NRLM fuel using existing hydrotreaters no longer being used to produce 500 ppm highway fuel. The total investment cost is roughly half that projected in the NPRM ($ 600 million). The decrease is due to a greater volume of 500 ppm NRLM fuel coming from existing hydrotreaters. This conclusion is based on the number of refineries leaving the highway diesel fuel market according to the refiners' highway program pre compliance reports. The investment per refinery that we projected in the NPRM 355 ($ 9.7 million) was essentially unchanged. Operating costs will be about $ 4.9 million per year for the average refinery, or slightly greater than that projected in the NPRM ( due to higher hydrogen costs and a lower percentage of hydrocrackate in the NRLM pool). The average cost of producing 500 ppm NRLM fuel in 2007 will be 1.9 cents per gallon, 0.3 cent per gallon lower than that projected in the NPRM, due primarily to the reduced capital expenditure.

In 2010, an additional $ 1170 million will be invested in revamped and new desulfurization equipment, $ 1090 million to meet the 15 ppm nonroad fuel cap and $ 80 million to produce 500 ppm NRLM fuel no longer eligible for a small refiner exemption to sell high sulfur NRLM fuel. In 2012, an additional $ 590 million will be invested in revamped and new desulfurization equipment to meet the 15 ppm L& M cap Finally, in 2014 an additional $ 210 million will be invested in additional 15 ppm fuel capacity. Thus, total capital cost of new equipment and revamps related to the NRLM fuel program will be $ 2280 million, or $ 36 million per refinery, roughly 5 percent greater than that projected in the NPRM. Total operating costs will be about $ 8.1 million per year for the average refinery, slightly lower than that projected in the NPRM ($ 8.3 million per year). The total refining cost, including the amortized cost of capital, will be 5.0, 5.6 and 5.8 cents per gallon of new 15 ppm NRLM fuel in 2010, 2012, and 2014, respectively.

The 500 pm NRLM fuel being produced in 2010 is projected to cost 2.7 cents per gallon. The cost of this 500 ppm fuel is higher than that projected in the NPRM, due primarily to a higher cost for natural gas in the future. The 500 pm, small refiner fuel being produced in 2012 is projected to cost 2.9 cents per gallon. All of these costs are relative to the cost of producing high sulfur fuel today, and includes the cost of meeting the 500 ppm standard beginning in 2007.

The 15 ppm refining costs are significantly higher than the 4.4 cent per gallon cost projected in the NPRM for the option where L& M fuel was controlled to 15 ppm in addition to nonroad fuel. The increase is due to the changes in refining cost methodology described above, particularly the reduced use of advanced desulfurization technology, reduced synergies with the highway fuel program and increased natural gas costs.

The average refining costs by refining region are shown in table VI. A 4 below. These costs include consideration of the small refiner provisions. Combined costs are shown for PADDs 1 and 3 because of the large volume of diesel fuel which is shipped from PADD 3 to PADD 1. 202 See chapter 7 of the RIA for further details regarding our estimation of distribution costs.

356 Table VI. A 4.   Average Refining Costs by Region ( cents per gallon)

500 ppm Cap 15 ppm Cap 2007 2010 2010 2012 2012 2014 2010 2012 2012 2014 2014+

PADDs 1 & 3 1.6 3.7 2.5 4.6 4.9 5.1 PADD 2 2.8 2.9 3.7 7.1 7.8 7.8 PADD 4 3.3 9.0 9.0 11.6 11.7 11.8 PADD 5 1.2 2.8 3.5 4.3 4.3 5.7 Nationwide 1.8 2.7 2.9 5.0 5.6 5.8 Fuel Only Control Programs: We used the same methodology to estimate refining costs for stand alone 500 ppm and 15 ppm NRLM fuel programs. The fully phased in refining impacts of a 15 ppm NRLM standard are the same as those described above for the final rule in 2014 and beyond. A fully phased in 500 ppm NRLM fuel program is projected to affect 63 refineries, cost 2.0 cents per gallon and require a capital investment of $ 480 million.

2. Distribution Costs Today's rule is projected to impact distribution costs in four ways. First, we project that a slightly greater volume of diesel fuel will have to be distributed, due to the fact that some of the desulfurization processes reduce the fuel's volumetric energy density during processing. Total energy is not lost during processing, as the total volume of fuel is increased in the hydrotreater. However, a greater volume of fuel must be consumed in the engine to produce the same amount of power. We project that desulfurizing diesel fuel to 500 ppm will reduce volumetric energy content by 0.7 percent. The cost of which is equivalent to 0.08 cent per gallon of affected NRLM fuel. 202 We project that desulfurizing diesel fuel to 15 ppm will reduce volumetric energy content by an additional 0.52 percent. This will increase the cost of distributing fuel by an additional 0.05 cents per gallon, for a total cost of 0.13 cents per gallon of affected 15 ppm NRLM fuel.

The second impact on distribution costs relates to the disposition of 15 ppm fuel contaminated during pipeline shipment. We received comments that the control of L& M fuel sulfur content, particularly to 15 ppm, would make it difficult to sell off specification 15 ppm fuel. The comments argued that much of this material would have to be shipped back to refineries and reprocessed to meet the 15 ppm cap. We designed the program finalized today to allow the continued sale of 500 ppm fuel into the NRLM market until June 1, 2014, and into the locomotive and marine market indefinitely. By doing so, we were able to minimize, though not eliminate, 357 much of the reprocessing and distribution cost impacts of concern. We have evaluated both the production and potential sale of distillate interface and estimated the distribution cost impacts of today's final rule provisions. The details of this analysis are contained in chapter 7 of the Final RIA.

In our analysis of the 15 ppm highway fuel program, we projected that the need to protect the quality of 15 ppm highway diesel fuel would increase the volume of highway diesel fuel downgraded to a lower value product, such as high sulfur diesel fuel and heating oil, from its current level of approximately 2.2 percent to 4.4 percent. Under today's rule, we expect that 15 ppm NRLM fuel will be shipped together with 15 ppm highway. Thus, the size of each batch of 15 ppm fuel will increase, but the number of batches will not. As the downgrade occurs at the interface between batches, the volume being downgraded should not increase. At the same time, we are not projecting that interface volume will decrease, as high sulfur fuels, such as jet fuel and, in some cases heating oil, will still be in the system.

The issue here is the market to which this interface volume can be sold. When this interface volume meets the specifications of one of the two fuels being shipped next to each other, the interface is simply added to the batch of that fuel. For example, the interface between regular and premium gasoline is added to the regular grade batch. Or, the interface between jet fuel and heating oil is added to the heating oil batch. One interface which is never added to either adjacent batch is a mixture of gasoline and any distillate fuel, such as jet or diesel fuel. If this interface was added to the distillate batch, the gasoline content in the interface would result in a violation of the distillate's flash point specification. If this interface was added to the gasoline batch, it would cause the gasoline to violate its end point specification. Therefore, this interface must be shipped to a transmix processor to separate the mixture into naphtha ( a sub octane gasoline) and distillate. The 2007 highway diesel fuel program will not change this practice. The naphtha produced by transmix processors from gasoline/ distillate mixtures is usually blended with premium gasoline to produce regular grade gasoline. The distillate produced is an acceptable high sulfur diesel fuel or heating oil, though if the feed material was primarily low sulfur distillate and gasoline it will likely also meet the current 500 ppm highway fuel cap.

With the implementation of the highway diesel rule, there is another incompatible interface, that between jet fuel and 15 ppm diesel fuel. This interface can not be cut into jet fuel due to end point and other concerns. However, it can usually be cut into 500 ppm diesel fuel as long as the sulfur level of the jet fuel is not too high. With the lowering of the highway standard to 15 ppm, however, this will no longer be possible. We expect that pipelines minimize this interface by abutting jet fuel and high sulfur distillate in the pipeline whenever possible. However, it will be unavoidable under many circumstances. A substantial part of the pipeline distribution system currently does not handle high sulfur distillate, and we expect that the highway program and today's rule will likely cause additional pipeline systems to discontinue carrying high sulfur distillate. Pipelines that do not carry high sulfur distillates will generate this interface whenever 203 We expect that only three types of fuel will be carried by such pipeline systems: jet fuel, 15 ppm diesel fuel, and gasoline ( premium and regular). Premium and regular gasolines are always shipped next to each other so the interface between premium and regular gasoline can be cut into the batch of regular gasoline. Thus, whenever jet fuel is shipped it will abut 15 ppm diesel fuel on one end and gasoline on the other.

204 See chapter 7.1.7 of the RIA regarding our analysis of the sulfur levels of this interface material. This analysis indicated that although the maximum sulfur specification of jet fuel 3,000 ppm,

in use jet fuel sulfur levels are frequently below 500 ppm.

358 they ship jet fuel. 203 The highway rule, and today's rule projects that pipeline operators will segregate this interface by cutting it into a separate storage tank. Because this interface can be sold as 500 ppm NRLM fuel or heating oil, and because these markets exist nationwide, there is little impact beyond the need for refiners to produce more 15 ppm highway diesel fuel ( compared to the volume of highway diesel fuel produced prior to the implementation of the 15 ppm standard), which was considered as part of the refining costs in the highway diesel rule.

With control of nonroad fuel to 15 ppm sulfur in 2010 and LM fuel to 15 ppm sulfur in 2012, the opportunities to downgrade interface to another product become increasing limited. Where limited this will increase costs due to the need to transport the interface to where it can be marketed or to a facility for reprocessing. In areas with large heating oil markets, such as the Northeast and the Gulf Coast, the control of NRLM sulfur content will still have little impact on the sale of this interface. However, in areas lacking a large heating oil market, the sale of this distillate interface will be more restricted. Because this interface will composed of 15 ppm diesel fuel and jet fuel, we estimate that the distillate interface created should nearly always meet a 500 ppm cap. 204 Thus, this interface can be added to 500 ppm NRLM batches ( as well as heating oil, where it is present at the terminal) through 2014. After 2014, this 500 ppm interface fuel can only be sold as L& M fuel or heating oil. An exception to this applies in the Northeast/ Mid Atlantic Area, where this interface cannot be sold into the nonroad fuel market after 2010, nor into the L& M fuel market after 2012.

In chapter 7 of the Final RIA, we estimate the costs related to handling this interface fuel during the four time periods ( 2007 2010, 2010 2012, 2012 2014, and 2014 and beyond). We project that there will be no additional costs prior to 2010, as 500 ppm fuel will be the primary NRLM fuel and be widely distributed. Beyond 2010, we estimate that terminals will have to add a small storage tank for this fuel, as 500 ppm highway diesel fuel and the majority of 500 ppm NRLM disappears from the distribution system. In many places, this interface will be the primary, if not sole source of 500 ppm fuel, so existing tankage to add this interface to will be limited. We have also added shipping costs to transport this fuel to NRLM and heating oil users. The volume of this interface is significant, sometimes a sizeable percentage of the combined NRLM fuel and heating oil markets. In the post 2014 period, the volume of this interface fuel is larger than the combined L& M fuel and heating oil markets in certain PADDs. Also, the volume of interface 359 received at each terminal will vary substantially, depending on where that terminal is on the pipeline. The advantage of this is that where the interface accumulates it may be of sufficient volume to justify marketing as a separate grade of fuel. Conversely, the potential users of this 500 ppm interface fuel may not be located near the terminals with the fuel necessitating additional transportation costs.

Prior to 2014, 500 ppm fuel can be used as NRLM fuel and heating oil outside of the Northeast/ Mid Atlantic Area. Additional storage tanks will be needed in some cases, as this will be the only source of 500 ppm fuel in the marketplace. Amortizing the cost of a range of storage tank sizes over 15 years of weekly shipments at a seven percent rate of return before taxes costs produced an amortized cost of 0.2 1.6 cents per gallon. These costs include the carrying cost of the fuel stored in the tank. We estimate that the average storage cost will be closer to the lower end of this range, or 0.5 cent per gallon. Nonroad fuel users are fairly ubiquitous. Thus, increased shipping distances should be fairly short. We estimated 45 miles at a cost of roughly 1.5 cents per gallon. The distance to L& M fuel users will likely be longer, roughly 100 miles, but cost the same due to greater efficiencies of rail transport. It will likely cost more to deliver interface fuel to heating oil users, as many of these users are smaller, not evenly dispersed geographically, purchase fuel seasonally, and lack rail connections. We estimate that transport distances will increase an average of 85 miles and cost an additional 3.0 cents per gallon over today's costs to deliver this fuel to the end user, in addition to the 0.5 cent per gallon storage cost. When spread over all the 15 and 500 ppm NRLM fuel being produced from 2010 2014 due to today's rule, the additional distribution cost from 2010 2014 is 0.4 cents per gallon.

Starting in 2014, this interface fuel can no longer be sold to the nonroad fuel market. Since the interface volume does not change, this increases the volume of fuel that must be sold to the L& M and heating oil markets. Thus, overall, transportation distances and costs will likely increase. We expect that the transportation cost for fuel sold to the L& M market will increase from 1.5 to 3.0 cents per gallon, while that for heating oil will increase to 5.0 cents per gallon, both including fuel storage. However, in PADD 5, the volume of interface generated exceeds the total fuel demand of these two markets. Thus, we estimate that some fuel will have to be shipped back to refineries and reprocessed to meet a 15 ppm cap and shipped out a second time. We estimate that the cost of this shipping and reprocessing will cost 10 cents per gallon. When spread over all the 15 ppm NRLM fuel being produced after 2014 due to today's rule, the additional distribution cost is 0.8 cent per gallon.

The third impact of today's rule on distribution costs is related to the need for additional storage tanks to market additional product grades at bulk plants. While this final rule minimizes the segregation of similar fuels, some additional segregation of products in the distribution system will still be required. The allowance that highway and NRLM diesel fuel meeting the same sulfur specification can be shipped fungibly until it leaves the terminal obviates the need for additional storage tanks in this segment of the distribution system except for the limited tankage at terminals 205 Including the refinery, pipeline, terminal, marine tanker, and barge segments of the distribution system.

206 This estimated cost includes the addition of a separate delivery system on the tank truck.

207 To avoid sulfur contamination of NRLM fuel, the tank compartment would need to be flushed with some NRLM fuel prior to switching from carrying heating oil to NRLM fuel.

360 necessary to handle 500 ppm sulfur interface fuel discussed above. 205 Today's final rule also allows 500 ppm NRLM diesel fuel to be mixed with high sulfur NRLM ( though it can no longer be sold as 500 ppm fuel).

However, we expect that the implementation of the 500 ppm standard for NRLM diesel fuel in 2007 will compel some bulk plants in those parts of the country still distributing heating oil as a separate fuel grade to install a second diesel storage tank to handle this 500 ppm NRLM fuel. These bulk plants currently handle only high sulfur fuel and hence will need a second tank to continue their current practice of selling fuel into the heating oil market in the winter and into the nonroad market in the summer. We believe that some of these bulk plants will convert their existing diesel tank to 500 ppm fuel in order to avoid the expense of installing an additional tank. However, to provide a conservatively high estimate we assumed that 10 percent of the approximately 10,000 bulk plants in the U. S. ( 1,000) will install a second tank in order to handle both 500 ppm NRLM diesel fuel and heating oil.

The cost of an additional storage tank at a bulk plant is estimated at $ 90,000 and the cost of de manifolding a delivery truck is estimated at $ 10,000.206 In the NPRM, we estimated that each bulk plant that needed to install a new storage tank would need to de manifold a single tank truck. Thus, the NPRM estimated the cost per bulk plant would be $ 100,000. Fuel distributors stated that the assumptions and calculations made by EPA in characterizing costs for bulk plant operators seem reasonable. However, they also stated that our estimate that a single tank truck would service a bulk plant is probably not accurate. No suggestion was offered regarding what might be a more appropriate estimate other than the number is likely to be much greater. Part of the reason why we estimated that only a single tank truck would need to be de manifolded, is that we expected that due to the seasonal nature of the demand for heating oil versus nonroad fuel, it would primarily only be at the juncture of these two seasons that both fuels would need to be distributed in substantial quantities. We also expected that the small demand for heating oil in the summer and the small demand for nonroad fuel in the winter could be serviced using a single demanifolded truck. The primary fuel distributed during a given season would be distributed by single compartment tank trucks. During the crossover between seasons, bulk plant operators would switch the fuel to which such single compartment tank trucks are used from nonroad to heating oil and back again. 207 Nevertheless, we agree that the subject bulk plant operators would likely be compelled to de manifold more that a single tank truck. Lacking additional specific information, we believe that assuming that each bulk plant operator de manifolds three tank trucks will provide a conservatively high estimate of the cost to bulk plant operators due to today's rule. 208 See Section IV of today's preamble for additional discussion of our rational for this conclusion.

361 If all 1,000 bulk plants were to install a new tank and de manifold three tank trucks, the cost for each bulk plant would $ 120,000, and the total one time capital cost would be $ 120,000,000. To provide a conservatively high estimate of the costs to bulk plant operators, we are assuming that all 1,000 bulk plants will do so. Amortizing the capital costs over 20 years, results in a estimated cost for tankage at such bulk plants of 0.1 cents per gallon of affected NRLM diesel fuel supplied. Although the impact on the overall cost of the program is small, the cost to those bulk plant operators who need to put in a separate storage tank may represent a substantial investment. Thus, we believe many of these bulk plants will search out other arrangements to continue servicing both heating oil and NRLM markets such as an exchange agreement between two bulk plants that serve a common area.

As a consequence of the end of the highway program's temporary compliance option ( TCO) in 2010 and the disappearance of high sulfur diesel fuel from much of the fuel distribution system resulting from the implementation of today's rule, we expect that storage tanks at many bulk plants that were previously devoted to 500 ppm TCO highway fuel and high sulfur fuel will become available for dyed 15 ppm nonroad fuel service. Based on this assessment, we do not expect that a significant number of bulk plants will need to install an additional storage tank in order to provide dyed and undyed 15 ppm diesel fuel to their customers beginning in 2010 ( the implementation date for the 15 ppm nonroad standard) .208 There could potentially be some additional costs related to the need for new tankage in some areas not already carrying 500 ppm fuel under the temporary compliance option of the highway diesel program and which continue to carry high sulfur fuel. However, we expect them to be minimal relative to the above 0.1 cent per gallon cost. Thus, we estimate that the total cost of additional storage tanks at bulk plants that will result from today's rule will be 0.1 cent per gallon of affected NRLM diesel fuel supplied.

The fourth impact on fuel distribution costs is a result of the requirement that high sulfur heating oil be marked beginning June 1, 2007 and that 500 ppm sulfur LM diesel produced by refiners or imported be marked from 2010 through 2012 outside of the Northeast/ Mid Atlantic Area and Alaska. The NPRM projected that there would be no capital costs associated with the proposed marker requirement. We proposed that the marker would be added at the refinery gate, and that the current requirement that non highway fuel be dyed red at the refinery gate be made voluntary. Thus, we believed that the refiner's additive injection equipment that is currently used to inject red dye into off highway diesel fuel could instead be used to inject the marker as needed. As a result of the allowance provided in today's final rule that the marker be added at the terminal rather than the refinery gate, and our reevaluation of the conditions for dye injection at the refinery, we are now assessing capital costs for terminals and refiners related to compliance with the fuel marker requirements.

Except for fuel that is distributed directly from a refiner's rack, today's final rule allows the marker to be added at the terminal rather than at the refinery as we proposed ( see section IV. D for 209 A refinery rack functions similar to a terminal in that it distributes fuel by truck to wholesale purchaser consumers and retailers.

210 Small refiner and credit high sulfur NRLM will not be permitted to be sold in the area where terminals are not required to add the fuel marker to heating oil ( the " Northeast/ Mid Atlantic Area"). See section IV. D.

362 a discussion of the fuel marker requirements). 209 We expect that except for fuel dispensed directly from the refinery rack, the fuel marker will be added to at the terminal to avoid the potential for marked fuel to contaminate jet fuel during distribution by pipeline. Terminals that need to inject the fuel marker will need to purchase a new injection system, including a marker storage tank and a segregated line and injector for each truck loading station at which fuel that is required to be marked is dispensed. Terminals will still be subject to IRS red dye requirements, and thus will not be able to rededicate such injection equipment to inject the fuel marker. Due to concerns regarding the need to maintain a visible evidence of the presence of the fuel marker, today's rule also contains a requirement that nay fuel which contains the fuel marker also contains visible evidence of red dye. Furthermore, there is little chance to adapt parts of the red dye injection system ( such as the feed lines and injectors) for the alternate injection of red dye and the fuel marker due to concerns that NRLM fuel become contaminated with the marker.

Terminal operators expressed concern regarding the potential burden on terminal operators from the capital costs of adding new additive injection equipment for heating oil. In response to these comments, today's rule includes provisions that exempt terminal operators from the fuel marker requirements in a geographic " Northeast/ Mid Atlantic Area" and Alaska. 210 These provisions provide that any heating oil or 500 ppm sulfur LM diesel fuel that would otherwise be subject to the fuel marker requirements which is delivered to a retailer or wholesale purchaser consumer inside the Northeast/ Mid Atlantic Area or Alaska does not need to contain the marker. The costs of the marker requirements for heating oil beginning in 2007 and for 500 ppm sulfur LM diesel fuel from 2010 through 2012 are discussed separately below.

The Northeast/ Mid Atlantic Area was defined to include the region where the majority of heating oil in the country is projected to continue to be supplied though the bulk distribution system ( the Northeast and Mid Atlantic). The vast majority of heating oil consumption in the U. S. will be within the Northeast/ Mid Atlantic Area. Outside of the Northeast/ Mid Atlantic Area, we expect that only limited quantities of heating oil will be supplied, primarily from certain refiner's racks. We estimate that 30 refineries and transmix processor facilities outside of the Northeast/ Mid Atlantic Area will distribute heating oil from their racks ( in limited volumes) on a sufficiently frequent basis to warrant the installation of a marker injection system at a total one time cost of $ 1,500,000.

Terminals outside of the Northeast/ Mid Atlantic Area will mostly be located in areas without continued production and/ or bulk shipment of heating oil. Consequently, any high sulfur 211 The estimated marker injection equipment costs include the cost of marker storage tanks,

lines, and injectors.

363 diesel fuel they sell will typically be NRLM. Terminals located within the Northeast/ Mid Atlantic Area will not need to mark their heating oil, except for those few that choose to ship heating oil outside of the Northeast/ Mid Atlantic Area. The terminals most likely to install marker injection equipment will therefore be those in states outside the Northeast/ Mid Atlantic Area with modest markets for heating oil after the implementation of this program. As discussed in chapter 7 of the RIA, in analyzing the various situations, we project that fewer than 60 terminals nationwide will choose to install marker injection equipment at a total cost of $ 4,150,000.211 The total capital cost to refiners and terminals to install marker injection equipment is estimated to be $ 5,650,000. Thus, the Northeast/ Mid Atlantic Area provisions in today's rule minimizes the number of terminals that will need to install additive injection equipment and its associated cost to comply with the marker requirement for heating oil.

In the NPRM we estimated that the cost to blenders of the fuel marker in bulk quantities would translate to 0.2 cents per gallon of fuel treated with the marker. This estimate was based on the fee charged by a major pipeline to inject red dye at the IRS concentration into its customers diesel fuel. We used this estimate because we lacked specific cost information on the proposed marker, and we believed that it provided a conservatively high estimate of marker cost. Since the proposal, we received input from a major distributor of fuel markers and dyes, regarding the cost of bulk deliveries of the specified fuel marker to terminals which translates to a cost of 0.03 cents per gallon of fuel treated with the marker. The volume of heating oil that we expect will need to be marked has also decreased substantially from that estimated in the NPRM due to the Northeast/ Mid Atlantic Area provisions. We estimate that 1.4 billion gallons of heating oil will be marked annually, for an annual marker cost of $ 425,000. In the NPRM, we projected that the cost of marking heating oil would continue for three years ( 2007  2010). Under today's final rule, heating oil must be marked indefinitely beginning in 2007, but only outside of the Northeast/ Mid Atlantic Area and Alaska.

Because heating oil outside of the Northeast/ Mid Atlantic Area is being marked to prevent its use in NRLM engines, for the purposes of estimating the impact of the marker requirement on the cost of the NRLM program we have spread the cost for the marker for heating oil over NRLM diesel fuel. Amortizing the capital costs of marker injection equipment over 20 years, results in an estimated cost of 0.006 cents per gallon of affected NRLM diesel fuel supplied. Spreading the cost of the marker over the volume of affected NRLM fuel results in an estimated cost of 0.003 cents per gallon of affected NRLM fuel. Adding the amortized cost of the injection equipment necessary to add the marker to heating oil and the cost or the marker results in a total estimated cost of the marker requirement for heating oil in today's rule of 0.01 cents per gallon of affected NRLM fuel.

The final NRLM rule also requires that 500 ppm L& M fuel produced at refineries or imported be marked from mid 2010 through mid 2012 outside of the Northeast/ Mid Atlantic Area 364 and Alaska. The adoption of a 15 ppm sulfur standard for LM diesel fuel in 2012 in today's rule allows us to require that LM fuel be marked from 2010 through 2012 rather than from 2010 through 2014 as proposed ( see section IV. A). In addition, the way in which the program was crafted to avoid requiring the fuel marker be added to heating oil in the Northeast/ Mid Atlantic Area and Alaska allows us to also provide that 500 ppm sulfur LM diesel fuel in these areas is not subject to the marker requirement ( see section IV. D). We project that only a small number of refiners will produce 500 ppm sulfur diesel fuel subject to the marker requirements fuel and that it will not be shipped via pipeline. Thus, most of this fuel can be marked at the refinery, limiting the number of facilities which need to add marking equipment in response to this requirement. We estimate that 15 facilities will have to do so, at a cost of $ 60,000 each, for a total of $ 900,000. Amortizing this over the total volume of affected NRLM fuel produced from mid 2010 to mid 2012 at seven percent per year before taxes yields a cost for the LM marker requirement of 0.004 cent per gallon. Including the cost of the marker ( 0.03 cent per gallon of marked fuel) increases this cost to 0.01 cent per gallon of NRLM fuel.

We summed these various costs incurred to the distribution system over four different time periods. As shown in table VI. A 5, the total additional distribution cost will be 0.2 cent per gallon of NRLM fuel during the first step of the fuel program ( from 2007 through 2010), 0.6 cents gallon of NRLM fuel from 2010 to 2012 and from 2012 to 2014, and increase to 1.0 cent per gallon thereafter. A more detailed description of the costs associated with downgraded jet fuel and 15 ppm diesel fuel is presented in chapter 7 of the Final RIA.

Table VI. A 5.   Summary of Distribution Costs ( cents per gallon)

Cause of Increase in Distribution Costs Time Period Over Which Costs Apply 2007 2010 2010 2012 2010 2014 2014+

Distribution of additional NRLM volume 0.08 0.1 0.1 0.1 Distillate interface handling 0 0.4 0.4 0.8 Bulk plant storage tanks 0.1 0.1 0.1 0.1 Heating oil and L& M fuel marker 0.01 0.02 0.01 0.01 Total 0.2 0.6 0.6 1.0 3. Cost of Lubricity Additives Hydrotreating diesel fuel tends to reduce the natural lubricating quality of diesel fuel, which is necessary for the proper functioning of certain fuel system components. There are a variety of fuel additives which can be used to restore diesel fuel's lubricating quality. These additives are currently used to some extent in highway diesel fuel. We expect that the need for lubricity additives that will result from the proposed 500 ppm sulfur standard for NRLM diesel fuel will be 212 Please refer to section IV in today's preamble for additional discussion regarding our projections of the potential impact on fuel lubricity of this proposed rule.

365 similar to that for highway diesel fuel meeting the current 500 ppm sulfur cap standard. 212 Industry experience indicates that the vast majority of highway diesel fuel meeting the current 500 ppm sulfur cap does not need lubricity additives. Therefore, we expect that the great majority of NRLM diesel fuel meeting the proposed 500 ppm sulfur standard will also not need lubricity additives. In estimating lubricity additive costs for 500 ppm diesel fuel, we assumed that fuel suppliers will use the same additives at the same concentration as we projected will be used in 15 ppm highway diesel fuel. Based on our analysis of this issue for the 2007 highway diesel fuel program, the cost per gallon of the lubricity additive is about 0.2 cents. This level of use is likely conservative, as the amount of lubricity additive needed increases substantially as diesel fuel is desulfurized to lower levels. We also project that only five percent of all 500 ppm NRLM diesel fuel will require the use of a lubricity additive. Thus, we project that the cost of additional lubricity additives for the affected 500 ppm NRLM diesel fuel will be 0.01 cent per gallon. See the Final RIA for more details on the issue of lubricity additives. We have no reason to expect that the implementation of today's NRLM sulfur standards will impact diesel properties other than fuel lubricity in such a way as to require the use of additives.

We project that all NRLM fuel meeting a 15 ppm cap will require treatment with lubricity additives. Thus, the projected cost will be 0.2 cent per affected gallon of 15 ppm NRLM fuel.

4. How EPA's Projected Costs Compare to Other Available Estimates Historically, the price of highway diesel fuel meeting a 500 ppm sulfur cap has exceeded that of high sulfur diesel fuel, ranging from 0 5 cents per gallon from 1995 99 and averaging 2.2 cent per gallon over this time period ( see chapter 7 of the Final RIA). Fuel prices are often a function of market forces which might not reflect the cost of producing the fuel. Still, given this is a five year average price difference, it is likely a reasonable indication of the cost of reducing highway diesel fuel sulfur to 500 ppm. Once the small refiner provisions applicable to 500 ppm fuel expire in 2010, we project that the total cost of the 500 ppm NRLM fuel cap will be 2.4 cents per gallon, well within the range of the historical highway high sulfur fuel price difference. This similarity exists despite changes in a number of factors. One, our projection of future natural gas costs are significantly higher than those existing during the above price comparison. Two, the refineries producing highway diesel fuel historically likely did so because they faced lower costs than those refineries continuing to produce high sulfur distillate. Three, desulfurization catalyst efficiency has improved dramatically since the highway units were installed and significant operating experience has been obtained on highway units. Four, inflation since the early 1990' s will have increased the cost of constructing the same hydrotreater. Five, and perhaps most importantly, the construction of some new hydrotreaters to produce 15 ppm highway diesel fuel will allow the existing hydrotreaters to produce 500 ppm NRLM fuel at no capital cost. Thus, there are at least five significant factors, two of which would tend to decrease costs and three of which would tend to increase costs. It is not surprising that these factors could counter balance 213 Hirshfeld, David, MathPro, Inc., " Refining economics of diesel fuel sulfur standards,"

performed for the Engine Manufactuers Association, October 5, 1999.

366 each other, leading to the conclusion that the 500 ppm cap could be extended to NRLM fuel at roughly the same cost as for highway diesel fuel.

The only existing market for 15 ppm diesel fuel is a niche market for fleets and the prices for this fuel likely bear little resemblance to the costs of the 15 ppm highway or NRLM caps. Thus, the only cost comparisons which can be made are those between engineering studies. One such study was performed by Mathpro for the Engine Manufactures Association ( EMA). Mathpro estimated the cost of controlling the sulfur content of highway and NRLM fuel to levels consistent with both 500 ppm and 15 ppm cap standards. 213 A detailed evaluation of the Mathpro costs is presented in the Final RIA. There are a number of aspects of the study that make direct comparisons between its estimates and our cost estimates difficult. Nonetheless, a crude comparison of 15 ppm costs indicates that our average cost range of 5.7 5.9 cent per gallon is quite similar to the 5.4 6.6 cents per gallon cost range estimated by Mathpro.

The other available study of 15 ppm fuel costs was performed by Baker and O'Brien for API and submitted in response to the nonroad NPRM. Baker and O'Brien analyzed two NRLM fuel control scenarios, but neither one matched today's final NRLM fuel program. The scenario closest to today's program assumed that a NRLM fuel would be capped at 15 ppm in 2008. In this case, Baker and O'Brien projected that the refinery specific cost of 15 ppm NRLM fuel would range from 4 17 cents per gallon. This is higher than our projected range of 2 14 cents per gallon. In addition, as described in the next section, Baker and O'Brien projected that the volume of NRLM fuel produced at these costs would not fully satisfy NRLM fuel demand. Presumably, totally fulfilling NRLM fuel demand with domestic production would have cost more.

Baker and O'Brien described portions of their cost methodology and indicated some general assumptions which they made during the study. However, the absence of detail prevents any detailed comparisons of their results to ours. It was clear from their report, though, that Baker and O'Brien made a number of pessimistic assumptions about refiners' willingness to invest in desulfurization capacity and that this limited the number of refineries which they assumed would invest to meet the NRLM sulfur caps. This inevitably led to higher projected costs ( and lower production volumes), than if all refineries had been considered. Thus, it is not surprising that they would derive slightly higher costs for a much smaller volume of fuel. A more detailed evaluation of the Baker and O'Brien cost estimates can be found in the Final RIA and RTC.

5. Supply of Nonroad, Locomotive and Marine Diesel Fuel We have developed today's NRLM fuel program to minimize its impact on the supply of distillate fuel. For example: we have split the control of NRLM fuel to 15 ppm sulfur into two steps, providing 8 years of leadtime for the final step. We are proposing to provide flexibility to refiners through the availability of banking and trading provisions. We have provided relief for 367 small refiners and hardship relief for any qualifying refiner. We are also allowing 500 ppm diesel fuel generated in the distribution system to be sold as L& M fuel indefinitely.

In the NPRM, we evaluated four possible reasons why refiners might reduce their production of NRLM fuel: 1) chemical processing loses during the desulfurization process, 2) refiners might leave the NRLM fuel market, 3) refiners might stop operations altogether ( i. e., shut down), and 4) refiners might remove certain blendstocks from the fuel pool to reduce desulfurization costs. In all four cases, we concluded that the answer was no, that the supply of NRLM fuel would likely remain adequate after implementation of the proposed fuel program. All of these findings started from the position that there would be adequate supply of diesel fuel after implementation of the 2007 highway diesel fuel program.

Several commenters, namely API and NPRA, took issue with the above four sets of arguments, as well as with our conclusion that refiners would not reduce NRLM fuel production. While not requesting any changes to the 2007 highway diesel fuel program, they reiterated previous concerns that supply shortages could occur under the highway diesel fuel program, even without the added challenge of producing low sulfur NRLM fuel. The primary basis for their comments was a study they had sponsored by Baker and O'Brien, which evaluated the costs and likely supply impacts of the proposal.

Baker and O'Brien evaluated two NRLM fuel scenarios: 1) a 15 ppm NRLM fuel cap starting in 2008, and 2) a 500 ppm NRLM fuel cap starting in 2008, followed by a 15 ppm cap only for nonroad fuel in 2010. First, Baker and O'Brien projected that 13 refineries with a total crude oil capacity of 971,000 barrels per day would close in response to the 2007 highway rule, roughly half in 2006 and half in 2010. ( Total U. S. refining capacity is currently 16 million barrels per day.) Then Baker and O'Brien projected that adding a 15 ppm NRLM cap would cause all of the refineries shutting down in 2010 to close in 2008, plus one additional refinery ( for a total of 14). Delaying the 15 ppm cap until 2010 and leaving L& M fuel at 500 ppm reduced the number of refineries projected to close in 2008, but did not change Baker and O'Brien's projection that 14 refineries would close by 2010. Given the fact that Baker and O'Brien projected the same number of refinery closures for scenarios # 1 and # 2, it is reasonable to assume that they would project similar results for today's final NRLM fuel program. 214 Closure would occur at the beginning of the 15 ppm highway fuel program, or 2006.

368 Table VI. A 6.   Projected Refinery Closures: API Sponsored Study by Baker and O'Brien No. of Refineries Lost Crude Capacity ( 1000 bbl/ day)

2008 2010 2008 2010 2007 Highway Fuel Program 8214 13 504 971 Plus One Step 15 ppm NRLM Program 14 14 1043 1043 Plus Two Step NRLM Program 12 14 924 1043 As a result of these refinery closures, Baker and O'Brien projected shortfalls in 15 and 500 ppm supply domestic refiners. The net shortfalls are shown in table VI. A 7 below. Baker and O'Brien stated that imports would have to make up the shortfall, with potentially high price impacts.

Table VI. A 7.   Projected Shortfall in Near Term Diesel Fuel Supply ( 1000 barrels per day)

15 ppm Fuel 500 ppm Fuel 2008 2010 2008 2010 2007 Highway Fuel Program 359 579 308 22 Plus One Step 15 ppm NRLM Program 684 930 165 0 Plus Two Step NRLM Program 351 639 481 82 To put these projected shortfalls in context, Baker and O'Brien projects total diesel fuel demand to be 3.3 million barrels per day in this timeframe ( slightly lower than our own projection summarized above). Thus, these projected shortfalls total roughly 10 20 percent of total diesel fuel demand, which if true, would be very significant.

We evaluated the Baker and O'Brien study and their findings. Baker and O'Brien made very pessimistic assumptions regarding the likelihood that refiners would invest in desulfurization capacity. Their judgment that a refinery would close rather than invest also was apparently based only on what they perceived to be excessively high desulfurization costs. Baker and O'Brien presents no information regarding the location of these refineries, the competition they face, costs related to closing down, nor the profits that they would forego by closing. Baker and O'Brien also makes no mention of EPA's special provisions for refiners facing economic hardship, nor the small refiner provisions. 369 We believe that it is not possible to project refinery closures without considering these factors. This is supported by comments made in response to our proposal of the 2007 highway diesel fuel program by Mathpro and the National Economic Research Associates. While we are aware of a couple of refineries that are being offered for sale and whose plans for producing low sulfur fuels are uncertain, we have no indications of as many as eight refineries closing in 2006 in response to the highway fuel program. In addition, despite uncertainties at a few refineries, refiners' pre compliance reports for the highway fuel program indicate that they are planning to produce a sufficient supply of 15 and 500 ppm highway diesel fuel from 2006 2010. Therefore, there is ample evidence that Baker and O'Brien's projections for the highway diesel fuel program are overly pessimistic. It therefore appears likely that their projection that the NRLM fuel program will cause an additional refinery to close is also overly pessimistic. The reader is referred to the RTC for a summary of these comments and our detailed response to them.

In their comments, API also challenged our findings that refiners would maintain sufficient supply under the proposed NRLM fuel program. After a careful review of their comments and other information newly available since the NPRM, we do not believe that the arguments presented by API and NPRA justify changing our position that 1) chemical processing loses during the desulfurization process will be very small, 2) refiners will be unlikely to leave the NRLM fuel market, and 3) refiners are unlikely to shut down due to this rule.

Regarding point # 1, the distillate material lost during desulfurization, our position is that the amount lost is small ( two percent), and most of it is lost in the form of naphtha which can be blended into gasoline. Refiners can then adjust their mix of gasoline and distillate production to compensate. API claimed that in the winter, refiners were already at maximum distillate production and could not shift any additional heavy gasoline material into the distillate pool. API did not present any evidence that this is in fact the case. The fact that some refiners actually crack distillate material into gasoline makes it difficult to accept their position.

Regarding point # 2, refiners leaving the NRLM fuel market, we argued that the only high sulfur distillate market remaining after 2007 was heating oil. Heating oil demand is flat or declining over time. We project that over 30 domestic refiners will still be able to produce heating oil after 2007, while other refiners will be able to produce sufficient quantities of NRLM fuel. If more refiners choose to produce heating oil, this market will be oversupplied and prices will drop significantly. Exporting high sulfur distillate is a possibility for some refiners, but this entails both transport costs, as well as relatively low prices overseas. Thus, a decision to not invest in NRLM fuel desulfurization has to be compared to the losses involved with the other options. API argued that some refiners face much higher desulfurization costs than others and this would lead those refiners to leave the NRLM fuel market. API did not estimate the losses that refiners would entail when they left the market. Studies performed for the highway fuel program indicate that these losses can be quite significant and inappropriate conclusions can be drawn if they are ignored. The highway program pre compliance reports also indicate that some highway fuel refiners are planning on leaving the highway fuel market in 2006, while others will enter it for the first time. Decisions 215 Shifting NRLM fuel blendstocks to heating oil is essentially the same as leaving the NRLM market, which was discussed under Point # 2 above.

370 to stay in or leave the NRLM fuel market are analogous. We have no reason to believe refiners would approach this market any differently than the highway market.

Regarding point # 3, refineries shutting down, API again pointed towards the high costs faced by some refineries and the fact that a number of refineries have shut down over the past ten years. There have been a number of refinery closures over the past decade, though the trend has slowed considerably. API pointed towards two specific refineries which identified EPA's gasoline and diesel fuel sulfur controls as prime reasons for their shutting down. A closer look at these situations showed that the future capital investment related to the sulfur controls could have been a contributing factor. However, these refineries faced many other challenges and the timing of their closure ( 2000 and 2001, respectively) showed that the EPA rules were not the direct cause. The refiner involved did not approach EPA concerning any relief from the rules' requirements due to economic hardship. Thus, the connection between their closure and our sulfur controls appears even more tenuous.

Another example of a refinery closure unrelated to desulfurization costs was Shell's recent decision to close their refinery in Bakersfield, California. The reason was an insufficient supply of crude oil being produced locally.

Analogous to a decision to leave the NRLM fuel market, shutting down completely involves the total loss of any profit being made on the production of other fuels. API presented no economic calculations or projections showing that it would be in the best interest of any refiner to shut down rather than invest in NRLM fuel desulfurization.

This leaves point # 4, that refiners might shift NRLM fuel blendstocks to other markets. This is really only an issue if the blendstocks are shifted to a non distillate market. 215 The most likely place that NRLM fuel blendstocks might be shifted is to the residual fuel market. In particular, heavy ( material with high densities and high distillation temperatures) LCO and LCGO could be shifted to residual fuel using existing refining equipment. The heavy portions of these two blendstocks contain the greatest concentrations of sulfur which is the most difficult to remove. Shifting this material to residual fuel, which currently does not have a sulfur standard, would reduce the size and cost of desulfurization equipment needed to meet a 15 ppm cap. Or, it would increase the volume of 15 ppm NRLM fuel which could be produced in an existing hydrotreater.

To evaluate this possibility, we estimated the cost of processing LCO ( the worse of the two blendstocks) into 15 ppm diesel fuel for each domestic refinery. On average, desulfurizing LCO to 15 ppm sulfur cost 11.4 cents per gallon. However, in some cases, this cost reached 15 cents per gallon. The cost to process heavy LCO could be twice these amounts, since the concentration of both total sulfur and the most difficult to remove sulfur are concentrated in the heaviest molecules. 371 A review of historic fuel prices showed that residual fuel is usually priced 25 30 cents per gallon less than diesel fuel. The highest incremental desulfurization costs for heavy LCO could potentially exceed this loss. Thus, a few refiners could find it economical to shift a portion of their LCO to the residual fuel market. The U. S. residual fuel market is small relative to the distillate fuel market, flat, and already being fulfilled. Worldwide, the residual fuel market is shrinking. Thus, it is unlikely that large volumes of LCO could leave the NRLM fuel market. However, we cannot rule out the possibility that some LCO, particularly that produced by capital strapped refiners, could be shifted to residual fuel. To estimate the upper limit of this shift, we estimated the volume of heavy LCO produced by refineries whose LCO processing costs exceeded 12 cents per gallon and which were not owned by large, integrated oil companies or small refiners. This costly, heavy LCO represents 0.4 percent of total NRLM fuel demand, a very small volume. In this case, we would expect that this loss could easily be made up by increased imports of 15 ppm diesel fuel or domestic refiners facing lower 15 ppm NRLM fuel costs.

Overall, we expect that domestic refiners will continue to produce sufficient supplies of NRLM fuel. The greatest potential for near term loss will be due to the possibility that some refiners might decide to limit their capital investment in desulfurization capacity by shifting some heavy LCO to the residual fuel market.

Fuel Only Control Programs: The potential supply impacts of a long term 500 ppm NRLM cap would necessarily be less than those of today's final NRLM fuel program. In particular, desulfurizing " difficult" blendstocks, like LCO, to 500 ppm is not technically challenging and does not have the potential to cost more than would be lost in shifting LCO or heavy LCO to residual fuel. The capital investment to meet a 500 ppm cap is also half of that needed to meet a 15 ppm cap or less. Thus, the likelihood that raising this capital would prove difficult is much less. Given that we expect the final fuel program to have a very minimal impact on supply, a 500 ppm NRLM cap would be negligible.

The potential impact of a long term 15 ppm NRLM cap is the same as that for today's final fuel program.

6. Fuel Prices It is well known that it is difficult to predict fuel prices in absolute terms with any accuracy. The price of crude oil dominates the cost of producing gasoline and diesel fuel. Crude oil prices have varied by more than a factor of two in the past two years. In addition, unexpectedly warm or cold winters can significantly affect heating oil consumption, which affects the amount of gasoline produced and the amount of distillate material available for diesel fuel production. Economic growth, or its lack, affects fuel demand, particularly for diesel fuel. Finally, both planned and unplanned shutdowns of refineries for maintenance and repairs can significantly affect total fuel production, inventory levels and resulting fuel prices. 216 Executive Order 13211, " Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use" ( 66 FR 28355, May 22, 2001).

372 Predicting the impact of any individual factor on fuel price is also difficult. The overall volatility in fuel prices limits the ability to determine the effect of a factor which changed at a specific point in time which might have led to the price change, as other factors continue to change over time. Occasionally, a fuel quality change, such as reformulated gasoline or a 500 ppm cap on diesel fuel sulfur content, only affects a portion of the fuel pool. In this case, an indication of the impact on price can be inferred by comparing the prices of the two fuels at the same general location over time. However, this is still only possible after the fact, and cannot be done before the fuel quality change takes place.

Because of these difficulties, EPA has generally not attempted to project the impact of its rules on fuel prices. However, in response to Executive Order 13211, we are doing so here. 216 To reflect the inherent uncertainty in making such projections, we developed three projections for the potential impact of the proposed fuel program on fuel prices. The range of potential long term price increases are shown in table VI. A 8. ( Due to their similarity, we have grouped the potential price impacts for similar quality fuels in the 2010 2012 and 2012 2014 time periods.) Short term price impacts are highly volatile, as are short term swings in absolute fuel prices, and much too dependent on individual refiners' decisions, unexpected shutdowns, etc. to be predicted even with broad ranges. 373 Table VI. A 8.   Range of Possible Total Diesel Fuel Price Increases ( cents per gallon) a Maximum Operating Cost Average Total Cost Maximum Total Cost 500 ppm Sulfur Cap: Nonroad, Locomotive and Marine Diesel Fuel ( 2007 2010)

PADDs 1 and 3 2.9 1.8 4.5 PADD 2 3.0 2.5 3.8 PADD 4 3.7 3.5 6.1 PADD 5 1.2 1.5 1.5 15 ppm Sulfur Cap: NRLM Fuel ( 2010 2014)

PADDs 1 and 3 5.6 5.7 9.4 PADD 2 7.3 7.4 10.8 PADD 4 7.9 12.6 13.6 PADD 5 4.5 5.1 5.2 15 ppm Sulfur Cap: NRLM Fuel ( fully implemented program: 2014 +)

PADDs 1 and 3 7.7 6.3 9.8 PADD 2 7.7 7.9 11.2 PADD 4 8.3 13.0 13.9 PADD 5 5.1 6.9 7.3 Notes: a At the current wholesale price of approximately $ 1.00 per gallon, these values also represent the percentage increase in diesel fuel price.

The lower end of the range assumes that prices within a PADD increased to reflect the highest operating cost increase faced by any refiner in that PADD ( please see the Final RIA for details on this methodology). This refiner with the highest operating cost will not recover any of his invested capital, but all other refiners will recover some or all of their investment. In this case, the price of NRLM fuel will increase in 2007 by 1   3 cents per gallon, depending on the area of the country. In 2010, the price of 15 ppm NRLM fuel will increase a total of 3   7 cents per gallon. In 2014, under this pricing scenario, 15 ppm NRLM fuel prices will increase slightly, to 4   7 cents per gallon. The increase in 2014 is due to the expiration of the small refiner provisions, as well as the 217 " Potential Impacts of Environmental Regulations on Diesel Fuel Prices," NERA, for AAM,

December 2000.

374 fact that 500 ppm fuel created in the distribution system can no longer be sold to the land based nonroad market.

The mid range estimate of price impacts assumes that prices within a PADD increase by the average refining and distribution cost within that PADD, including full recovery of capital ( at seven percent per annum before taxes). Lower cost refiners will recover more than their capital investment, while those with higher than average costs recover less. Under this assumption, the price of NRLM fuel will increase in 2007 by 1 3 cents per gallon, depending on the area of the country. In 2010, the price of 15 ppm NRLM fuel will increase a total of 4   11 cents per gallon. In 2014, under this pricing scenario, 15 ppm NRLM fuel prices will increase slightly, to 5   11 cents per gallon.

The upper end estimate of price impacts assumes that prices within a PADD increase by the maximum total refining and distribution cost of any refinery within that PADD, including full recovery of capital ( at seven percent per annum before taxes). All other refiners will recover more than their capital investment. Under this assumption, the price of NRLM fuel will increase in 2007 by 1   4 cents per gallon, depending on the area of the country. In 2010, the price of 15 ppm NRLM fuel will increase a total of 4   13 cents per gallon. In 2014, under this pricing scenario, 15 ppm NRLM fuel prices will increase further to 6   13 cents per gallon. All these potential price impacts for 500 and 15 ppm fuel, relative to those projected in the NPRM, reflect the differences in cost estimates discussed above.

There are a number of assumptions inherent in all three of the above price projections. First, both the lower and upper limits of the projected price impacts described above assume that the refinery facing the highest compliance costs is currently the price setter in their market. This is a worse case assumption which is impossible to validate. Many factors affect a refinery's total costs of fuel production. Most of these factors, such as crude oil cost, labor costs, age of equipment, etc., are not considered in projecting the incremental costs associated with lower NRLM diesel fuel sulfur levels. Thus, current prices may very well be set in any specific market by a refinery facing lower incremental compliance costs than other refineries. This point was highlighted in a study by the National Economic Research Associates ( NERA) for AAM of the potential price impacts of EPA's 2007 highway diesel fuel program. 217 In that study, NERA criticized the above referenced study performed by Charles River Associates, et. al. for API, which projected that prices will increase nationwide to reflect the total cost faced by the U. S. refinery with the maximum total compliance cost of all the refineries in the U. S. producing highway diesel fuel. To reflect the potential that the refinery with the highest projected compliance costs under the maximum price scenario is not the current price setter, we included the mid point price impacts above. It is possible that even the lower limit price impacts are too high, if the conditions exist where prices are set based on operating costs alone. However, these price impacts are sufficiently 218 " Cost of Diesel Fuel Desulfurization In Asian Refineries," Estrada International Ltd., for the Asian Development Bank, December 17, 2002.

375 low that considering even lower price impacts was not considered critical to estimating the potential economic impact of this rule.

Second, we assumed in some cases that a single refinery's costs could affect fuel prices throughout an entire PADD. While this is a definite improvement over analyses which assume that a single refinery's costs could affect fuel prices throughout the entire nation, it is still conservative. High cost refineries are more likely to have a more limited geographical impact on market pricing than an entire PADD. In many cases, high cost refiners continue to operate simply because they are in a niche location where transportation costs limit competition.

Third, by focusing solely on the cost of desulfurizing NRLM diesel fuel, we assume that the production of NRLM diesel fuel is independent of the production of other refining products, such as gasoline, jet fuel and highway diesel fuel. However, this is clearly not the case. Refiners have some flexibility to increase the production of one product without significantly affecting the others, but this flexibility is quite limited. It is possible that the relative economics of producing other products could influence a refiner's decision to increase or decrease the production of NRLM diesel fuel under today's fuel program. It is this price response that causes fuel supply to match fuel demand. And, this response in turn could increase or decrease the price impact relative to those projected above.

Fourth, all three of the above price projections are based on the projected cost for U. S. refineries of meeting the NRLM fuel sulfur caps. Thus, these price projections assume that imports of NRLM fuel, which are currently significant in the Northeast, are available at roughly the same cost as those for U. S. refineries in PADDs 1 and 3. We have not performed any analysis of the cost of lower sulfur caps on diesel fuel produced by foreign refiners. However, there are reasons to believe that imports of 500 and 15 ppm NRLM diesel fuel will be available at prices in the ranges of those projected for U. S. refiners.

One recent study analyzed the relative cost of lower sulfur caps for Asian refiners relative to those in the U. S., Europe and Japan. 218 It concluded that costs for Asian refiners will be comparatively higher, due to the lack of current hydrotreating capacity at Asian refineries. This conclusion is certainly valid when evaluating lower sulfur levels for highway diesel fuels which are already at low levels in the U. S., Europe and Japan and for which refineries in these areas have already invested in hydrotreating capacity. It appears to be less valid when assessing the relative cost of meeting lower sulfur standards for NRLM fuels and heating oils which are currently at much higher sulfur levels in the U. S., Europe and Japan. All refineries face additional investments to remove sulfur from these fuels and so face roughly comparable control costs on a per gallon basis. 219 See Heavy duty 2007 Highway Final RIA, Chapter V. C. 5, and " Study of the Effects of Reduced Diesel Fuel Sulfur Content on Engine Wear," EPA report # 460/ 3 87 002, June 1987.

376 One factor arguing for competitively priced imports is the fact that refinery utilization rates are currently higher in the U. S. and Europe than in the rest of the world. The primary issue is whether overseas refiners will invest to meet tight sulfur standards for U. S., European and Japanese markets. Many overseas refiners will not invest, instead focusing on local, higher sulfur markets. However, many overseas refiners focus on exports. Both Europe and the U. S. are moving towards highway and nonroad diesel fuel sulfur caps in the 10   15 ppm range. Europe is currently and projected to continue to need to import large volumes of highway diesel fuel. Thus, it seems reasonable to expect that a number of overseas refiners will invest in the capacity to produce some or all of their diesel fuel at these levels. Many overseas refiners also have the flexibility to produce 10 15 ppm diesel fuel from their cleanest blendstocks, as most of their available markets have less stringent sulfur standards. Thus, there are reasons to believe that some capacity to produce 10   15 ppm diesel fuel will be available overseas at competitive prices. If these refineries were operating well below capacity, they might be willing to supply complying product at prices which only reflect incremental operating costs. This could hold prices down in areas where importing fuel is economical. However, it is unlikely that these refiners could supply sufficient volumes to hold prices down nationwide. Despite this expectation, to be conservative, in the refining cost analysis conducted earlier in this chapter, we assumed no imports of 500 ppm or 15 ppm NRLM diesel fuel. All 500 ppm and 15 ppm NRLM fuel was produced by domestic refineries. This raised the average and maximum costs of 500 ppm and 15 ppm NRLM diesel fuel and increased the potential price impacts projected above beyond what would have been projected had we projected that 5 10 percent of NRLM diesel fuel will be imported at competitive prices.