Acid Rain Program: Permits, Allowance System, Sulfur Dioxide Opt- Ins, Continuous Emission Monitoring, Excess Emissions, and Appeal Procedures

SUMMARY: Title IV of the Clean Air Act (the Act) authorizes the

Environmental Protection Agency (EPA or Agency) to establish the Acid

Rain Program. The purpose of the Acid Rain Program is to significantly

reduce emissions of sulfur dioxide and nitrogen oxides from utility

electric generating plants in order to reduce the adverse health and

ecological impacts of acidic deposition (or acid rain) resulting from

such emissions. On January 11 and March 23, 1993, the Agency

promulgated final rules governing permitting, the allowance system,

continuous emissions monitoring, excess emissions, and appeal

procedures.

After considering its experience in applying these rules since

1993, the Agency believes that the permitting, excess emissions, and

appeal procedures rules (as well as minor aspects of the monitoring

rule) can be streamlined and improved in order to reduce the burden on

utilities, State and local permitting authorities, and EPA. The rule

revisions in today's proposal streamline the Acid Rain Program while

still ensuring achievement of its statutory goals of reducing sulfur

dioxide and nitrogen oxides emissions.

In addition, EPA is revising allocations of sulfur dixoxide

allowances. Each allowance authorizes the emission of one ton of sulfur

dioxide. Under the Acid Rain Program, utility units (i.e., fossil fuel-

fired boilers or turbines) are allocated allowances and must not emit

sulfur dioxide in excess of the amount authorized by the allowances

that they hold. EPA proposes to revise certain units' allowances in

response to litigation, in light of Agency errors in making the

allocations or errors in data relevant to whether facilities are

covered by the Acid Rain Program, or because of more recent information

concerning the construction or commercial operation of new units.

DATES: Comments on the regulations proposed by this action must be

received on or before January 27, 1997.

ADDRESSES: Comments. All written comments must be identified with the

appropriate docket number (Docket No. A-95-56) and must be submitted in

duplicate to EPA Air Docket Section (6102), Waterside Mall, Room M1500,

1st Floor, 401 M Street, SW, Washington DC 20460.

Docket. Docket No. A-95-56, containing supporting information used

to develop the proposal is available for public inspection and copying

from 8:30 a.m. to 12 p.m. and 1 p.m. to 3:30 p.m., Monday through

Friday, excluding legal holidays, at EPA's Air Docket Section at the

above address. Information concerning the original rules and some of

the revisions proposed today is found in Docket Nos. A-90-38 (permits),

A-91-43 and A-92-06 (allowances), A-90-51 (continuous emissions

monitoring), A-91-68 (excess emissions), A-91-69 (general), and A-93-15

(appeals). A reasonable fee may be charged for copying.

FOR FURTHER INFORMATION CONTACT: Kathy Barylski, at (202) 233-9074,

U.S. Environmental Protection Agency, 401 M St. SW, Acid Rain Division

(6204J), Washington, DC 20460 (concerning revisions of parts 73 and

75); Dwight C. Alpern, Attorney-advisor, at (202) 233-9151 (same

address) (concerning all other revisions); or the Acid Rain Hotline at

(202) 233-9620.

SUPPLEMENTARY INFORMATION:

Regulated Entities

Entities potentially regulated by this action are fossil-fuel fired

boilers or turbines that serve generators producing electricity for

sale. Regulated categories and entities include:

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Examples of regulated

Category entities

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Industry.................................. Electric service providers

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This table is not intended to be exhaustive, but rather provides a

guide for readers regarding entities likely to be regulated by this

action. This table lists the types of entities that EPA is now aware

could potentially be regulated by this action. Other types of entities

not listed in the table could also be regulated. To determine whether

your facility is regulated by this action, you should carefully examine

the applicability criteria in Sec. 72.6 and the exemptions in

Secs. 72.7 and 72.8 of title 40 of the Code of Federal Regulations and

the revised Secs. 72.6, 72.7, 72.8, and 72.14 of the proposed rule. If

you have questions regarding the applicability of this action to a

particular entity, consult the persons listed in the preceding FOR

FURTHER INFORMATION CONTACT Section.

Organization

The information in this preamble is organized as follows:

I. Part 72: Applicability of and Exemptions from Acid Rain Program

A. Revisions Concerning Applicability

B. Revisions to Exemptions

1. Fuel Use and Fuel Testing Requirements Under New Units

Exemption

2. Administration of New Units Exemption

3. Retired Units Exemption

4. Industrial Units Exemption

II. Part 72: Interaction of Acid Rain Permitting and Title V

A. Relationship Between Acid Rain Rules and Parts 70 and 71

B. State Authority to Administer and Enforce Acid Rain Permits

C. Required Elements for State Acid Rain Program

III. Part 72: Miscellaneous Permitting Matters

A. Definitions

B. Designated Representative

C. Compliance Plans

l. Submission of Substitution and Reduced Utilization Plans

2. Repowering Extension Plans

D. Federal Permit Issuance

E. Permit Revision

F. Reduced Utilization Accounting

IV. Part 73: Allowances

A. Revision of Table 2 Allowances

l. Allocation Determinations Remanded to EPA

2. Correction of Agency Errors

B. Deletion of Units from Table 2

C. Additions of Units to and Deletions of Units From Table 3

D. 1998 Revision of Allowance Allocations

E. Revisions to Small Diesel Refinery Provisions

V. Part 75: Monitoring Requirements for Units Burning Digester or

Landfill Gas

VI. Part 77: Excess Emissions

A. Immediate Deduction of Allowances to Offset Excess Emissions

B. Deadline for Payment of Excess Emissions Penalties

C. Excess NOx Emissions Under NOX Averaging Plans

VII. Part 78: Administrative Appeals

VIII. Administrative Requirements

A. Executive Order 12866

B. Unfunded Mandates Act

C. Paperwork Reduction Act

D. Regulatory Flexibility Act

E. Miscellaneous

I. Part 72: Applicability of and Exemptions From Acid Rain Program

A. Revisions Concerning Applicability

Section 72.6 explains what types of units are ``affected units''

subject to emissions reduction or limitation

[[Page 68341]]

requirements and other requirements of the Acid Rain Program and what

types of units are not affected units. Under Sec. 72.6(b) (5) and (6),

qualifying facilities and independent power production facilities

meeting certain requirements are not affected units. One such

requirement is that the facility had, as of November 15, 1990, a

qualifying power purchase commitment, which may be in the form of a

letter of intent that is followed by a power sales agreement. Under

section 405(g)(6)(A) of the Act, the power sales agreement must be

executed ``within a reasonable time'' following the letter of intent.

In July 1992 (57 FR 29940, 29947 (July 7, 1992)), EPA proposed a two-

year deadline or no later than November 15, 1992 for execution of the

power sales agreement. That deadline was not commented on and was made

final in March 1993 (58 FR 15634, 15648 (March 23, 1993)).

Subsequently, EPA has received public comment that the two-year

deadline created a hardship for independent power producers negotiating

with multiple regulated purchasers.

To implement the statutory language regarding the time frame for

execution of a power sales agreement, EPA could set a fixed deadline

(as in the current rule) or could determine a reasonable time frame on

a case-by-case basis as part of an applicability determination.

Particularly where questions of the applicability of the Acid Rain

Program are involved, EPA maintains that it is preferable to establish

clear-cut lines. Moreover, EPA is concerned that the two-year period in

the current rule for execution of an agreement does not take account of

the time necessary to complete agreements where multiple utility

purchasers are involved.

Therefore, EPA is proposing to revise the deadline to three years

from letter of intent to execution of a power sales agreement. Since

under section 405(g)(6)(A) of the Act, the letter of intent must be in

place by November 15, 1990, this means that the power sales agreement

must have been executed by November 15, 1993, rather than by November

15, 1992 as under the current rule. Public comment indicates that the

additional year is reasonable for independent power producers

negotiating with multiple regulated purchasers. EPA requests comments

on this revision.

Section 72.6(c) sets out procedures for petitioning for a

determination from the Administrator as to whether a unit is an

affected unit covered by the Acid Rain Program. The current regulation

allows the submission of the petition by a certifying official, rather

than requiring that the unit have a designated representative who would

make the submission. However, the regulation has a general reference

to, and requires compliance with, Sec. 72.21, which requires that

submissions be made by a designated representative and include certain

certifications. To prevent confusion, EPA proposes revisions that

pinpoint the certification and notice requirements in Sec. 72.21 that a

certifying official's petition must meet. In addition, language is

added to Sec. 72.6(c)(1) to clarify that it is the certifying official

of an owner or operator of a unit that may submit a petition, and some

superfluous language is removed. Further, this section is revised to

allow a petition to be submitted at any time but indicating that, if

possible, the petition should be submitted before the issuance of an

Acid Rain permit. While EPA wants to facilitate the submission of

petitions where owners or operators are uncertain as to the status of

their unit under the Acid Rain Program, EPA's determination on the

petition may obviate the processing and issuance of a permit for the

unit.

B. Revisions to Exemptions

In the current rule, EPA established two exemptions from Acid Rain

Program requirements. First, in Sec. 72.7 EPA provided for an exemption

from requirements concerning permitting, allowances, and continuous

emissions monitoring for small, new units (i.e., units that commence

commercial operation on or after November 15, 1990 and serve generators

with a total nameplate capacity of 25 MWe or less) burning clean fuels.

The exemption was adopted because emissions from these units were

considered to be de minimis. 58 FR 3390, 3594 (January 11, 1993).

Second, in Sec. 72.8 EPA provided for an exemption from Phase II

permitting requirements for affected units that retire permanently

prior to the issuance of a Phase II Acid Rain permit. Units that

submitted petitions for such an exemption could also be exempted from

monitoring requirements under Sec. 75.67.

1. Fuel Use and Fuel Testing Requirements Under New Units Exemption

EPA is proposing to modify the limitation on fuel use and the

requirements for fuel testing under the new units exemption. Under the

current rule, units must use exclusively fuels with a sulfur content of

0.05 percent or less by weight, and specified tests to measure sulfur

content must be performed for each delivery of fuel (other than natural

gas, which is presumed to meet the sulfur content requirement). The

records of such tests must be retained at the source for 5 years.

In contrast, today's proposal requires units to use only gaseous

fuel with an annual average sulfur content of 0.05 percent by weight or

less and only nongaseous fuel that separately meets this same annual

average sulfur content limit. The proposal includes formulas for

calculating the annual average percentage sulfur content by weight for

gaseous fuels and for nongaseous fuels. Similar to the approach in the

current rule requiring sampling and sulfur content testing of fuel

deliveries, the formulas require use of the measured sulfur content of

periodic samples of fuel deliveries during the year to calculate the

annual average sulfur content of fuel burned during the year. The

formulas require sampling of fuel at least once for each delivery or,

for fuel that is delivered to the unit continuously by pipeline, at

least once each quarter that the fuel is delivered. Unlike the current

rule, the formulas do not require the use of any specific testing

methods to measure sulfur content. Sampling and testing of sulfur

content of fuel, which may be performed by the fuel supplier rather

than the unit's owners and operators, are necessary in order to

demonstrate whether the sulfur content limit is met. As under the

current rule, the owners and operators of an exempt unit bear the

burden of proving compliance with the requirements of the exemption.

However, if the only gaseous fuel burned is natural gas, the

proposal provides that the 0.05 percent annual average limit for

gaseous fuel is assumed to be met without making any calculations or

conducting any sampling or testing. This is consistent with the current

Sec. 72.7(d)(2)(ii), which provides that natural gas (which is defined

as a ``fluid mixture of hydocarbons containing'', inter alia, 20 grains

or less of sulfur (40 CFR 72.2)) is assumed to meet the 0.05 percent

limit on each delivery of fuel. Moreover, consistent with the current

rule, which excludes (through the 0.05 percent sulfur content limit on

each delivery) any use of coal by the units, and because the sulfur

content of a coal delivery is not necessarily uniform, the proposal

expressly bars the use of coal or coal-derived fuel (except coal-

derived gas with a sulfur content no greater than natural gas) by

exempt units.

EPA believes that the fuel use and testing requirements in the

proposal are sufficiently stringent to ensure that minimal emissions

from the exempt units and are significantly less

[[Page 68342]]

burdensome for the owners and operators of the units involved, which in

many cases are municipally owned units. Allowing a unit to burn some

fuel that exceeds 0.05 percent sulfur by weight so long as the annual

average sulfur content of its fuel (weighted by the weight of the fuel)

does not exceed that level will have little effect on the total

SO2 emissions for the year. Separate sulfur content limits are

established by gaseous and nongaseous fuels so that very clean gaseous

fuel (e.g., pipeline natural gas) cannot be used to offset nongaseous

fuel with a sulfur content significantly higher than 0.05 percent. EPA

notes that, under this approach, a unit will be able to use landfill or

digester gas, which has a higher sulfur content than natural gas but

lower than some nongaseous fuels.1 Using the annual average will

give owners and operators more flexibility in that a single delivery of

fuel in excess of the limit will not automatically invalidate the

exemption, as is the case under the current rule.

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\1\ This is consistent with EPA's efforts to encourage use,

rather than flaring, of such gas. See section V of this preamble.

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EPA also believes that prescribing more detailed testing methods is

unnecessary because the appropriate testing methods may vary depending

on the specific fuel involved and testing data from the fuel supplier

may be sufficient to establish the sulfur content of the fuel.2

The proposal requires owners and operators to keep records for 5 years

(or longer if required in writing by EPA or the permitting authority)

that demonstrate that the sulfur content limit has been met. This

approach gives owners and operators more flexibility to determine what

type of information will support such a demonstration, but the proposal

also emphasizes that the burden of proof is on the owners and

operators.

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\2\ With the elimination of the fuel testing requirements in the

current rule, the testing methodologies specified in the current

Sec. 72.7 and incorporated by reference in the current Sec. 72.13

are unnecessary, and EPA therefore proposes to remove them. The

provisions of Sec. 72.13 are renumbered to reflect this change.

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2. Administration of New Units Exemption

The purpose of the exemption, of course, is to relieve owners and

operators of the burden of complying with permitting, allowance, and

monitoring requirements for clean new units and to reduce the

concomitant administrative burden on permitting authorities. In issuing

new unit exemptions under the current rule, the Agency has found that

the procedures for obtaining and maintaining an exemption are somewhat

less burdensome than the procedural requirements for units required to

have Acid Rain permits. However, the Agency has concluded that the

exemption procedures are still more burdensome than necessary. In

particular, the current rule provides that: a potentially exempt unit

must have a designated representative and submit a petition for a

written exemption; the permitting authority must issue a written

exemption after providing public notice (e.g., in a local newspaper)

and a comment period; and the exemption must be renewed every five

years.

The current rule requires a significant amount of processing for

each unit that seeks to obtain an exemption. The Agency has already

granted about 130 new unit exemptions using current procedures, and,

despite extensive public notice, not one comment has been received

during the public comment periods. Based on its experience with these

exemptions, EPA does not believe that requiring a designated

representative to be appointed for each clean unit and submission and

processing of forms for a new units exemption every five years provides

any significant environmental benefit.

The proposal makes the new unit exemptions largely automatic for

those units that meet the criteria, discussed above, concerning

capacity, annual fuel use, and recordkeeping. In general, no designated

representative, petition for exemption, or renewal petition is

required.3

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\3\ Because the proposed new units exemption and, as discussed

below, the proposed retired units exemption, are automatic and

written exemptions for these units are no longer issued, the

references in the current part 72 to written exemptions under

Secs. 72.7 and 72.8 are revised. The revisions to these references

also reflect, in some cases, the establishment of exemptions for

industrial units under proposed Sec. 72.14, which is discussed

below. For example, the criteria for State acid rain programs in

Sec. 72.72(b) are changed to remove the reference to Secs. 72.7 and

72.8 written exemptions and to refer instead to Sec. 72.14

exemptions. By further example, the reference in Sec. 72.9(c)(6) to

Secs. 72.7 and 72.8 written exemptions is changed to refer to

exemptions under Secs. 72.7, 72.8, and 72.14. The same change--and

the only change proposed to part 74--is proposed in Sec. 74.2.

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The only exception to this approach is for units that are listed

and allocated one or more allowances on Table 2 or 3 of Sec. 73.10.

Because they are being exempt from the requirement to hold allowances

to cover emissions, they should not retain their allowance allocations.

The proposal requires the designated representative (who handle the

unit's allowance account) to submit to EPA and the State permitting

authority a statement that: the unit meets, and will continue to meet,

the exemption requirements; he or she is surrendering allowances in the

same amount, and of the same or earlier compliance use date as, the

unit's allocated allowances; and he or she is returning the proceeds

for any allowances withheld from the unit for EPA allowance auctions

under subpart E of part 73. However, apparently because the owners and

operators of some small units are small entities and not fully aware of

their obligations under the Acid Rain Program, some potentially exempt

units have still not selected designated representatives even though

the units are allocated allowances. In order to facilitate

implementation of the exemptions by small entities, the proposal

provides that, if there is no designated representative, a certifying

official of each owner of the unit may make this submission. This

reflects the desirability of ensuring that each owner (or the

designated representative representing all owners) is aware of the

allowance surrender. The unit will not be exempt until EPA actually

deducts the allowances from the unit account in the Allowance Tracking

System and receives the allowance auction proceeds. Upon deduction of

the allowances, the unit account is closed.

Although units that meet the exemption criteria and are not

allocated allowances are automatically exempt, the proposal requires

the designated representative (or a certifying official of each owner)

of such unit to submit to EPA and the State permitting authority a

statement that the unit meets and will continue to meet the exemption,

which are referenced in the statement. EPA anticipates providing a

standard form for designated representatives or certifying officials

for exempt units (whether or not they have allocated allowances) to

submit the appropriate information. Providing this type of notice to

EPA and the State permitting authorities imposes little burden on the

exempt units and has important benefits. First, owners of the units are

more likely to consider carefully the basis for the exemption and the

continuing requirements under the exemption if each owners'

representative must sign and submit such a form. Second, submission of

the form will ensure that EPA and State permitting authorities can keep

track of which units are exempt and will not treat such units as

affected units.

Under the proposal, a new units exemption is effective on January 1

of the first full calendar year for which the unit meets the criteria

for an exemption.

[[Page 68343]]

This reflects the annual nature of the Acid Rain Program. As provided

in the current rule, the exemption terminates automatically when the

unit involved no longer satisfies the criteria for an exemption.

Consistent with the approach taken with other exclusions of units from

the Acid Rain Program, a unit that had an automatic exemption that

terminates is an affected unit and cannot requalify for the exemption.

See 40 CFR 72.6(a)(3)(ii) through (vii). As in the current rule,

exemption termination subjects the unit to the permitting, allowance,

and monitoring requirements of the Acid Rain Program. The unit will

have to have a designated representative, who must submit a complete

permit application before the later of January 1, 1998 or 60 days after

the exemption terminates. The unit will have to comply with the

monitoring requirements within 90 days after the termination.

Under the current rule, exempt units are still included in the

definition of ``affected unit.'' As a result, they must generally be

included in title V operating permits issued by State permitting

authorities under part 70 and are not eligible to become opt-in units

under part 74. Part 70 requires sources with affected units to have

operating permits reflecting Acid Rain Program requirements and any

other Clean Air Act requirements to which the sources are subject. If a

unit is subject to other Clean Air Act requirements, the unit must

continue to comply with such non-title IV provisions, and this will be

reflected in the title V operating permit.4 However, if a unit is

not subject to any other Clean Air Act requirements and the unit is

exempt from Acid Rain permitting, allowance, and monitoring

requirements, question has been raised as to whether the current rule

can be read to require the unit to obtain a title V operating permit.

In such circumstances, it makes little sense to require a title V

operating permit; after all, the only requirements put in the permit

will be those for maintaining an exemption and a major purpose of the

exemption is to relieve the unit and the permitting authority of

permitting burdens. Although the Agency maintains that a title V

operating permit is not required for such a unit, the proposal modifies

Sec. 72.6(b) to make this explicit by stating that any exempt new unit

is an unaffected unit. Further, because the purpose of the exemption is

to relieve clean, new units of permitting and other Acid Rain

requirements, EPA continues to believe that exempt units should be

excluded from applying to re-enter the Acid Rain Program as opt-in

sources and the proposal contains such an exclusion.

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\4\ In order to ensure that owners and operators understand

this, today's proposal states this expressly. The proposed rule also

provides that a permitting authority may use the administrative

amendment procedures under Sec. 72.83 to add to the permit an

exemption under Sec. 72.7, 72.8, or 72.14.

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Finally, as discussed above, EPA has already approved a number of

written exemptions for new units under the current rule. Since the

proposal provides more flexible requirements for qualifying for and

maintaining the exemption (e.g., more flexible sulfur content

requirements and no renewal requirement), the units with written

exemptions also qualify for the automatic exemption under today's

proposal. The proposal makes this clear by including, as one category

of units that qualify for the automatic exemption, those new units that

have already been granted written exemptions. EPA sees no reason for

denying already exempt units the flexibility and streamlining benefits

of the proposal and also sees no purpose to retaining permanently two

different types of new units exemptions. Consequently, the proposal

provides that already exempt units must meet the requirements for

maintaining an automatic exemption, in lieu of the requirements

contained in the current rule.

However, while the current rule requires exempt units to surrender

any allowances allocated to the units under Sec. 73.10 for years for

which the units are exempt, the written exemptions already granted did

not extend beyond 5 years. The already exempt units have not yet

surrendered Phase II allowances and, under the current rule, will have

to do so when the exemption is renewed. In extending automatically

these exemptions and removing the need for renewal, the proposal

requires those exempt units with allocated allowances to surrender such

allowances and the proceeds from EPA's auctioning of such allowances.

3. Retired Units Exemption

While retaining the basic criteria in the current rule for

qualifying for the retired units exemption, EPA proposes to streamline

the procedures for obtaining and maintaining the exemption. In

addition, EPA proposes to clarify what Acid Rain requirements are

covered by the exemption.

The current rule requires largely the same procedures for the

retired units exemption as for the new units exemption: submission of a

petition, issuance of a written exemption subject to public notice and

comment, and submission of a renewal petition every 5 years. EPA has

approved about 155 retired units exemptions under these procedures

without receiving any public comments on them. Since the purpose of the

exemption is to reduce the burden on the owners and operators of

retired units and the permitting authorities, EPA believes that, as in

the case of new units exemptions, the procedures for retired units

exemptions can be made less burdensome.

The proposal takes essentially the same approach in setting revised

procedures for both new units and retired units exemptions. The

proposed retired units exemption is automatic so long as the unit meets

the criteria for the exemption: i.e., that the unit is permanently

retired and does not emit any SO2 or NOX starting on the

effective date of the exemption. Units that retire are not, of course,

necessarily small and, since they probably have been participating in

the Acid Rain Program until retirement, probably have designated

representatives. Under the proposal, the designated representative of

each exempt unit must submit to EPA and the State permitting authority

a statement that the unit meets, and will continue to meet, the

exemption requirements. EPA anticipates providing a standard form for

the designated representative of an exempt unit to submit the

appropriate information. Units already granted retired units exemptions

also qualify for the automatic exemption and will make no additional

submissions. As under the current rule, exempt retired units retain

their allocated allowances since, even without the exemption, they

would have no SO2 emissions and would not use any allowances. An

exempt unit's Allowance Tracking System account is subject to the

requirements for general accounts under part 73. The owners and

operators of the unit must retain at the source records demonstrating

that the unit qualifies for the exemption. The exemption terminates

automatically if the unit resumes operation and emits any SO2 or

NOX.

EPA is also proposing to modify the current rule to clarify what

Acid Rain requirements are covered by the exemption. Currently

Sec. 72.8 of the regulations exempts retired units only from the

requirements of part 72. Section 75.67(a) currently provides that units

that retire before January 1, 1995 and for which a petition for a

retired units exemption is submitted prior to monitor certification

deadlines may also obtain an exemption from the monitoring requirements

of part 75. The Agency maintains that any unit that retires should be

automatically exempt, starting in the first full year of

[[Page 68344]]

retirement, from both the Phase II permitting requirements of part 72

and the monitoring requirements of part 75 so long as the unit remains

retired. If the unit has no emissions, there is nothing to monitor. The

proposal removes Sec. 75.67(a) and adds the monitoring exemption to

Sec. 72.8.

However, as noted above, retired units may still receive allowance

allocations. Such units must remain subject to subpart B of part 73,

which governs allowance allocations. Reflecting these considerations,

the proposal exempts retired units from all Acid Rain Program

requirements except for the provisions of Secs. 72.2 through 72.6,

Sec. 72.8, Secs. 72.10 through 72.13, and subpart B of part 73.

Moreover, retired units that, but for the exemption under Sec. 72.7,

would be Phase I units, must still comply with the requirements

concerning Phase I Acid Rain permits and reduced utilization of such

units during Phase I.5 The purpose of the retired units exemption

is to exempt the units from Phase II permitting, not to allow them to

avoid requirements implementing statutory permitting and reduced

utilization provisions. In fact, the retired unit exemptions issued by

EPA under the current Sec. 72.8 state expressly that they apply to

Phase II (as distinguished from Phase I) permitting requirements. In

order to clarify that reduced utilization requirements apply to units

with retired unit exemptions, the proposal states that the units must

submit annual compliance certification reports that include the

accounting for reduced utilization and are subject to end-of-year

allowance deduction procedures for Phase I years.

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\5\ The definition of ``Phase I unit'' in Sec. 72.2 is revised

to make it clear that units that, but for a retired units exemption,

would be subject to an Acid Rain emission reduction requirement or

limitation continue to be treated as Phase I units.

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For the same reasons as under the proposed new units exemption, EPA

proposes that units under the retired units exemption be unaffected

units and that they be excluded from becoming opt-in sources.

Similarly, retired units already granted written exemptions will be

covered by the automatic exemption and must comply with the

requirements for maintaining such an exemption.

4. Industrial Units Exemption

The purpose of title IV is to reduce the adverse impacts of acid

deposition through reductions of SO2 and NOx emissions.

Congress addressed SO2 emissions of both ``utility units'' and

``industrial sources.'' While ``utility units'' are generally required

(starting in Phase I, if the unit is listed in Table A of section 404

or is otherwise a Phase I unit, or Phase II) to meet SO2 emissions

limitations and to hold allowances to cover their SO2 emissions,

``industrial sources'' are not specifically required to limit emissions

or hold allowances. Instead, section 406 of the Clean Air Act

Amendments of 1990 required the Administrator to prepare and submit to

Congress a report that inventories national annual SO2 emissions

from industrial sources. Whenever the inventory indicates that such

emissions ``may reasonably be expected to exceed 5.6 million tons per

year,'' the Administrator must ``take such actions under the Clean Air

Act as may be appropriate to ensure that such emissions do not exceed''

the 5.6 million ton cap. 42 U.S.C. 7656. These actions may include

promulgation of standards of performance for new or existing sources.

The statutory definitions of ``utility unit'' and ``industrial

source'' draw the line between facilities (utility units) that are

subject to the requirement to hold allowances by no later than January

1, 2000 and industrial sources that are not, but could be, made subject

to unspecified requirements if the industrial source cap is exceeded.

However, ``utility unit'' is broadly defined in section 402 of the Act

to encompass units owned by companies that are generally not treated as

full-fledged public utilities by State and federal utility regulatory

authorities.

Generally, for purposes of State utility regulation, a public

utility is an entity that owns or operates facilities whose product or

service is dedicated to public use. Typically, the company must devote

its facilities to serve the general public or a portion of the general

public, not simply selected contract customers.6 In contrast,

under section 201(e) of the Federal Power Act, any persons that sell

electricity that is in turn resold are ``public utilities'' and are

subject to regulation of their sales rates and other matters by the

Federal Energy Regulatory Commission (FERC). While holding that

industrial companies that sell utilities incidental amounts of

electricity from non-cogeneration units are themselves public

utilities, FERC has imposed less burdensome regulatory requirements on

such industrial sellers. For example, rate schedules for sales by these

industrial sellers must be filed with FERC but the rates are not

required to meet traditional cost-of-service standards, under which a

rate must be based on the seller's costs (including return on capital)

of providing the electricity. See, e.g., Ford Motor Co. and Rouge Steel

Co., 50 FERC para. 61,426 (1990), modified on reh'g, 50 FERC para.

61,025; Cliffs Electric Service Co., 32 FERC para. 61,372 at 61,833

(1985); Orange & Rockland Utilities, 42 FERC para. 61,012 (1988); St.

Joe Minerals Corp., 21 FERC para. 61,323 (1982), modified on rehg., 22

FERC 61,211 (1983).

---------------------------------------------------------------------------

\6\ See, e.g., Arkansas-Louisiana Electric Cooperative v.

Arkansas Public Service Comm'n, 194 S.W.2d 673, 678 (S.Ct. Arka.

1946); Richfield Oil v. Public Utilities Comm'n of California, 354

P.2d 4, 10-11 and 16 (S.Ct. Cal. 1960); Colorado Utilities v. Public

Service Comm'n, 61 P.2d 849, 854-55 (S.Ct. Colo. 1936); Mississippi

River Fuel v. Illinois Commerce Comm'n, 116 N.E.2d 394, 399 (S.Ct.

Ill. 1953); City of Saint Louis v. Mississippi River Fuel, 97 F.2d

726, 729-30 (8th Cir. 1938); Llano v. Southern Union Gas, 399 P.2d

646, 653 (S. Ct. N.Mex. 1964); Ambridge v. Public Sevice Comm'n of

Pennsylvania, 165 A. 47, 49 (S. Ct. Penn. 1933); Humble Oil and

Refining v. Railroad Comm'n of Texas, 128 S.W.2d 9, 13 (S.Ct. Tex.

1939); Valcour v. Morrisville, 184 A. 881, 885 (S. Ct. Ver. 1936);

Inland Empire Rural Electrification v. Dept. of Public Service of

Washington, 92 P.2d 258, 262-63 (S.Ct. Wash. 1939); Wilhite v.

Public Utilities Comm'n of West Virginia, 149 S.E.2d 273, 281 (S.Ct

W. Wir. 1966); and Union Falls Power v. Oconto Falls, 265 N.W. 722,

723 (S.Ct. Wisc. 1936) (cases holding that company that serve

public, not just selected customers, is public utility). But see

Southern Oklahoma Power v. Corporation Comm'n, 220 P. 370, 371

(S.Ct. Okla. 1923) (holding that generating company the only

customer of which is a public utility is itself a public utility).

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Under section 402 of the Clean Air Act, a utility unit is ``a unit

that serves a generator in any State that produces electricity for

sale,'' regardless of the amount of the sale relative to total

generation by the unit or generator or whether the sale is to the

general public or to a public utility for resale to the public. 42

U.S.C. 7651a(17)(A). Consequently, entities (such as independent power

producers, small power producers, and cogenerators) that sell

electricity to a public utility are affected units unless they qualify

for an exemption under other provisions of title IV. Section 402(17)(C)

establishes an exemption for units cogenerating steam and electricity:

a cogeneration unit is not a ``utility unit'' unless

the unit is constructed for the purpose of supplying, or

commences construction after [November 15, 1990] and supplies, more

than one-third of its potential electric output capacity and more

than 25 megawatts electrical output to any utility power

distribution system for sale. 42 U.S.C. 7651a(17)(C).

In addition, section 405(g)(6) establishes an exemption for ``qualifing

small power production facilities'', ``qualifying cogeneration

facilities'', and ``new independent power producers''. 42 U.S.C.

7651d(g)(6). Such entities (which are defined in sections 405(g)(6) and

416(a)(2)) that had a committment--through a power sales agreement, a

order of a State regulatory authority, a letter of intent, or selection

as a winning bidder in a competitive bid

[[Page 68345]]

solilcitation--as of November 15, 1990 to sell power are not affected

units. There are no such exceptions for industrial units that do not

fall within the exempt categories of units under these sections.

As a result, the requirements of title IV cover non-cogeneration

industrial units serving generators that produce electricity almost

exclusively for use by an industrial company and only incidentally for

sale to a public utility. In one such case, three units and three

generators (with a total nameplate capacity of about 190 MWe) are owned

and operated solely by the industrial company. Under the

interconnection agreement with a public utility and a related power

purchase agreement, the public utility provides additional electricity,

through backup and emergency service, for use by the industrial

company. The industrial company is in turn obligated to sell some

electricity on a backup and emergency basis to the public utility and,

starting in 1984, has made such sales, which have been less than 10

percent of total annual generation. The industrial company obtains

backup for its capacity, and the public utility avoids constructing

some additional capacity. Because these industrial units make limited

electricity sales only to the public utility, the company is apparently

not regulated by the State utility regulatory authority and is subject

to relatively light-handed FERC regulation. EPA has received public

comment suggesting that the units be exempt from the Acid Rain Program.

In order to determine the scope of the issue, EPA attempted to

estimate the number of units that might be covered by such an exemption

for industrial units. About 3,400 industrial combustion sources are

included in the 1990 Interim Inventory (a database based on the 1985

NAPAP inventory with emissions projections for 1995). EPA removed, from

this group of possibly affected industrial units, those industrial

units thought to be: self-generators consuming rather than selling

their generation; cogenerators exempt under section 402(17)(C); or

units exempt under section 402(b) because they were serving only

generators with a nameplate capacity of 25 MWe or less. EPA estimated

that about 140 remaining industrial units possibly may be affected

units under title IV. Based on discussions with industry

representatives and on review of the electric rate schedules filed at

FERC for electricity sellers that are not traditional utilities, EPA

concludes that most of these remaining industrial units are not selling

any electricity and that there are about 15 industrial units that sell

some electricity and so are affected units under the current Acid Rain

rules. See Report to Docket: Industrial Units.

Even if electricity sales to a public utility make up a very small

portion of the total amount of electricity produced by an industrial

unit and associated generator, the Acid Rain Program imposes allowance

requirements relating to all SO2 emissions from the unit. In such

a case, no distinction is made between emissions associated with the

small amount of electricity sales and emissions associated with the

vast majority of electricity used by the industrial company itself. An

affected industrial unit must hold allowances, as of the allowance

transfer deadline, that cover all of the unit's SO2 emissions

during the year. 40 CFR 72.9(c)(1)(i). Similarly, any NOx emission

limitation applicable to the industrial unit covers all NOx

emissions from the unit. See, e.g., 40 CFR 76.5, 76.6, and 76.7.

The cost to some industrial companies of holding sufficient

allowances may be exacerbated by the fact that, even though certain

existing industrial units could have qualified for allowance

allocations for Phase II under section 405 of the Act, none were

allocated any allowances. See 40 U.S.C. 73.10 (Tables 2 and 3, which do

not include any such units). Information on such units was not included

in the National Allowance Data Base (NADB), which was used to develop

allowance allocations. However, based on information compiled by the

Department of Energy on electric generators owned by nonutility

electric power producers, EPA developed and published the Adjunct Data

File, which listed units owned by ``nontraditional'' utilities. 57 FR

30034, 30040 (July 7, 1992). EPA noted that the listed facilities

potentially could be affected units, but that it did not have

sufficient information to make an applicabililty determination or to

allocate allowances to those that were affected units. Consequently, in

publishing the file, EPA requested owners or operators of units that

were then or might, in the future, become affected units to provide EPA

the data elements necessary for allocating allowances. In addition, EPA

gave notice that if the data was not provided by September 8, 1992, the

units involved would not be allocated any allowances and, to the extent

allowances were needed, would have to obtain them on the open market.

Id. A number of industrial companies submitted comments on the Adjunct

Data File, each arguing that their units were not affected units.

On March 23, 1993, EPA issued a notice stating that (with a few

exceptions not relevant here) that it ``believes'' that none of the

units in the Adjunct Data File were affected units. 58 FR 15720, 15727

(March 23, 1993). No allowances were allocated to industrial units in

the Adjunct Data File (including some units identified in Report to

Docket: Industrial Units as potentially covered by the proposed

industrial unit exemption) or to any other industrial units. However,

EPA stressed that the omission of a unit from the tables indicating

allowance allocations does not mean that the unit is an unaffected

unit: ``[a]pplicability will be determined under the (Acid Rain) rules

in 40 CFR 72.6.'' Id.

In addition to being required to hold allowances covering all

SO2 emissions and to meet any applicable NOx emission

limitation, an affected industrial unit, like all affected units, must

install, operate, and maintain continuous emission monitoring systems

for all SO2, NOx, and CO2 emissions and for opacity.

After EPA approves certification of the systems, they must be tested

periodically to ensure that the monitoring data is accurate. Further,

monitoring data (including hourly emissions data) must be reported to

EPA on a quarterly basis. The average cost per unit of acquisition,

installation, operation, and maintenance of a continuous emission

monitoring system (including data handling hardware) is estimated to be

about $90,600 (in 1993 dollars). Economic Analysis of the Title IV

Requirements of the 1990 Clean Air Act Amendments at 34 (ICF Resources

Inc. 1995) (estimating total annualized emission monitoring costs under

title IV of $200 million for 2,096 units during the period 1997-2010).

The costs of the Acid Rain Program are more likely to be a problem

for industrial companies than for public utilities, which in general

have greater ability to pass through to customers the costs of

acquiring allowances. First, public utilities generally are subject to

cost of service ratemaking and charge rates covering their costs of

service. Second, virtually all fossil fuel-fired utility generation is

covered by the Acid Rain Program. In contrast, the prices charged by

industrial companies for their industrial products are generally

limited by competitive market prices and relatively few industrial

units are covered by the program. Particularly if one industrial

company, but not its competitors, must meet the costs of the Acid Rain

Program as applied to its units, market prices will not necessarily

cover all such costs. EPA notes that in

[[Page 68346]]

section 405(g)(6)(A) cogeneration units that, as of November 15, 1990,

had already contracted or otherwise committed to sell electricity to a

public utility were exempted from the Acid Rain Program because of

their limited ability to pass through allowance costs to customers. 58

FR 15634, 15638 (March 23, 1993); see also Cong. Rec. S3027-28 (March

22, 1990).

In short, as a result of a very small portion of its operations

(i.e., incidental electricity sales to public utilities under existing

interconnection and power purchase agreements), a non-cogeneration

industrial unit may be subject to allowance and monitoring requirements

affecting all of its electric generation activities and imposing

significant costs.7 Further, once the industrial unit has begun

making any such incidental electricity sales, the unit becomes an

affected utility unit permanently subject to all the requirements of

the Acid Rain Program. In the absence of an exemption, such a unit is

an affected utility unit if, during 1985, it served a generator that

produced electricity sold to a public utility or if, at any time

thereafter, the unit serves such a generator. See 42 U.S.C.

7651a(17)(A). The unit remains an affected utility unit even if the

industrial company subsequently terminates its interconnection

agreement with and stops selling electricity to the public utility.

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\7\ The Acid Rain Program also requires the owners and operators

of affected industrial units to select a designated representative

and obtain an Acid Rain permit covering the units. While these

requirements impose some costs, the costs are relatively small.

---------------------------------------------------------------------------

EPA is concerned that, because of an incidental portion of the

operations of a non-cogeneration industrial unit, an industrial company

will be burdened with significant regulatory requirements and resulting

costs that were unanticipated when the incidental electricity sales

were made and that are unavoidable in that they remain even if the

incidental sales are now terminated. However, this concern applies only

where (1) the industrial units are not cogeneration units; (2) these

units serve generators that were contractually obligated to make

incidental sales under an interconnection agreement (and any related

power purchase agreement) and have made only incidential electricity

sales; and (3) this contractual obligation was effective on or before

March 23, 1993. This new exemption is not necessary for cogeneration

units since Congress already provided an exemption for cogeneration

units based on the amount of utility sales. Moreover, non-cogeneration

industrial units making more than incidental electricity sales should

be affected units since, in title IV, Congress generally applied the

Acid Rain Program to units serving generators that sell electricity.

The basis for limiting the exemption to units under a contractual

obligation as of March 23, 1993 is related to the Agency's handling of

allowance allocations for industrial units. After November 15, 1990,

industrial units' owners were on constructive notice that if they

contractually obligated themselves to sell electricity, they would be

subject to title IV requirements. However, as noted above, on March 23,

1993 EPA issued a notice stating that it believed that the industrial

units listed in the Adjunct Data File (a list of units owned by

``nontraditional utilities'') were unaffected units. 58 FR 15727. The

notice did not explain the basis for this ``belief'', which appears to

have been erroneous with regard to at least some of the listed

noncogeneration industrial units. As a result, EPA did not add the

industrial units to the allowance allocation tables and did not

allocate any allowances to these units. Id. Also on March 23, 1993, EPA

issued a final list of the Phase II allowance allocations under section

403(a) of the Act.8 58 FR 15634 (March 23, 1993). As discussed

below, EPA is today correcting certain Agency errors in the March 23,

1993 allocations. However, except for these limited corrections, EPA

will not allocate allowances to units that were not listed as receiving

allowance allocations in the March 23, 1993 notice and that become

affected units after that date. 58 FR 15641. Consequently, if, after

March 23, 1993, a non-cogeneration industrial unit becomes

contractually obligated to sell electricity to a utility and, by making

the sales, becomes an affected unit, the unit will not be allocated

allowances. Non-generation industrial units that were contractually

obligated on or before March 23, 1993 and were affected units probably

should have been, but were not, allocated allowances. Therefore, EPA

proposes to apply the new exemption to non-cogeneration industrial

units that were contractually obligated as of March 23, 1993.

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\8\ Section 403(a) required the final list of allowance

allocations to be published by December 31, 1992, but the final list

was issued late.

---------------------------------------------------------------------------

Under this approach, the non-cogeneration industrial units that

meet the exemption criteria and are issued an exemption may continue to

serve generators making incidential, contractually required electricity

sales and remain exempt. However, if the units serve generators that

make sales after the contractual obligation is no longer in effect or

to make sales beyond the contractual obligation, the units will become

affected units under the Acid Rain Program.

Exempting non-cogeneration industrial units will exempt their

SO2 emissions from the requirement to hold allowances and thus

from the 8.95 million ton cap in Phase II for utility units. The total

estimated annual SO2 emissions from exempt industrial units are

relatively small: about 47,000 tons. Report to Docket: Industrial

Units. The environmental impact of removing these units from the

utility unit cap is mitigated by the fact that emissions from the

exempt industrial units are still subject to the 5.6 million ton cap

for industrial sources. As discussed above, the Administrator is

required to take action under section 406 of the Clean Air Act

Amendments of 1990 to ensure that the industrial source cap is not

exceeded.

The industrial units exemption will also exempt these units from

Acid Rain NOX emissions limitations to the extent that the units

have coal-fired boilers of the types covered in Phase II. Again, the

total estimated annual NOX emissions from exempt units is

relatively small: about 19,000 tons. Id. In April 1995 EPA promulgated

NOX emission limitations for dry bottom wall-fired or tangentially

fired boilers. 60 FR 18751, 18763 (April 13, 1995). In January 1996,

EPA proposed to revise these limitations and establish new limitations

for most other types of existing coal-fired boilers. 61 FR 1442, 1480

(January 19, 1996).

For these reasons, EPA proposes to establish a narrow exemption for

non-cogeneration industrial units, i.e., non-cogeneration units that

have no owner or operator of which the principal business is

electricity sale, transmission, or distribution or that is a public

utility subject to State or local utility regulation. In determining

whether this requirement is met, any affiliate or subsidiary or parent

company of an owner or operator will be considered so that the

requirement cannot be circumvented through the position of the owner or

operator in a corporate structure. The exemption will apply where there

is a showing that, on or before March 23, 1993, the owners or operators

of the unit entered into an interconnection agreement (and any related

power purchase agreement) with a public utility requiring that

generators served by the unit produce electricity for sale only for

incidental sales of electricity to a public utility. There also must be

a showing that the unit served generators that, in 1985 and any year

thereafter, actually produced electricity

[[Page 68347]]

for sale only for incidental electricity sales to a public utility as

required under that interconnection agreement and any related power

purchase agreement. If any of the requirements of the exemption are not

met, the exemption terminates automatically.

Two aspects of the proposed exemption ensure that it is limited to

situations involving only incidental electricity sales. First, the

sales must be required under an interconnection agreement (and any

related power purchase agreement) between the owners or operators of

the industrial unit and the public utility to which the electricity

sales are made. The fact that the sales are made in connection with the

agreement through which the industrial company obtains electricity for

its own use from the public utility indicates that the sales are

incidental to the industrial company's business. Second, the sales to

the public utility must not exceed, in any calendar year, the lesser of

10 percent of the generating output capacity of the generator served by

the unit (which is the nameplate capacity of the generator times the

number of hours (8,760) in a year) for that year or 10 percent of the

actual annual electric output of the generator. EPA believes that these

limits on the amount of annual sales are reasonable and will help

ensure that the unit's electricity sales are truly incidental. Applying

these limits to a hypothetical industrial unit serving a generator with

nameplate capacity of 75 MWe, the generator output capacity is 657,000

MWe-hr. Assuming that the generator's actual annual electrical output

is 300,000 MWe-hr, this unit can sell up to 30,000 MWe-hr and qualify

for an industrial unit exemption under this proposal.

Because of EPA's lack of experience with this proposed exemption

and because applying the exemption criteria to specific cases may

require analysis and exercise of administrative judgment and may

benefit from public comment, EPA proposes to require submission of an

application for an exemption and provide for public notice and comment

before approving or disapproving the exemption for any industrial unit.

The designated representative of an industrial unit must submit an

application that provides the information necessary to rule on the

exemption. Using the procedures applicable to permit issuance, the

permitting authority will issue a draft exemption or denial of

exemption for public comment and then issue or deny a final exemption

(or proposed exemption if a State is the permitting authority). An

industrial unit with an approved exemption will become an unaffected

unit and will be exempt from the provisions of the Acid Rain Program,

except for the provisions of Sec. 72.14 (the new section providing for

and setting conditions on the exemption), Secs. 72.2 through 72.6,

Secs. 72.10 through 72.13. Like other exempt units, an exempt

industrial unit cannot become an opt-in source. The exemption need not

be renewed and is effective so long as the unit meets the requirements,

discussed above, for maintaining the exemption.

EPA requests comment on all aspects of the proposed industrial unit

exemption.

II. Part 72: Interaction of Acid Rain Permitting and Title V

Section 408 of the Act requires that title IV be implemented by

``permits issued to units subject to this title (and enforced) in

accordance with the provisions of title V, as modified by (title IV) .

. . No permit shall be issued that is inconsistent with the

requirements of (title IV), and title V as applicable.'' 42 U.S.C.

7651g(a).

Title V, in turn, sets forth requirements for permit programs to be

implemented by State and local air pollution control agencies. Under

title V, it is unlawful to operate an affected source in the Acid Rain

Program or other specified sources ``except in compliance with a permit

issued by a permitting authority under (title V).'' 42 U.S.C. 7652b(a).

The permit must include enforceable emission limitations and standards

and other conditions ``as are necessary to ensure compliance with

applicable requirements of (the Act).'' 42 U.S.C. 7652d(a). Title V

states that its provisions ``apply to permits implementing the

requirements of title IV except as modified by that title.'' 42 U.S.C.

7652f(b).

EPA proposes to revise the current regulations governing the

interaction of titles IV and V with regard to several matters: the

provisions explaining the relationship between the Acid Rain rules and

rules implementing title V (i.e., parts 70 and 71); establishment of

State authority to administer and enforce Acid Rain permits; and the

required elements of a State Acid Rain program.

A. Relationship Between Acid Rain Rules and Parts 70 and 71

The current part 72 states that parts 72 and 78 take precedence

over part 70 (which governs title V permitting) to the extent that any

requirements of parts 72 and 78 are ``inconsistent with'' part 70. 40

CFR 72.70(b). The current rules also state that part 72 governs Acid

Rain permitting by the Administrator but do not specifically address

the rules (i.e., part 71) for permitting by the Administrator under

title V since part 71 had not been issued when the current part 72 was

issued. See 40 CFR 72.60(a). As noted above, both titles IV and V

establish the precedence of the Acid Rain regulations over title V

regulations for purposes of administering Acid Rain permits. Since the

issuance of the current part 72 in January 1993, additional Acid Rain

regulations relating to permit administration (i.e., part 74 for opt-in

sources and part 76 for NOx emissions) have been promulgated. In

addition, part 71, setting forth permitting procedures for the

Administrator under title V, has been proposed and then issued as a

final rule. 61 FR 34202 (July 1, 1996).

EPA proposes today to revise the current provisions addressing the

relationship between Acid Rain and title V rules to reflect the

additional rulemaking activity. The revisions also clarify what

constitutes an ``inconsistency'' between the two sets of regulations

and the circumstances under which the Acid Rain rules take precedence.

With regard to State permitting activities, the proposal states in

Sec. 72.70(b) that parts 72, 74, 76, and 78 take precedence to the

extent that such parts ``contain provisions not included in, or

expressly eliminate or replace provisions of, part 70 concerning the

acid rain permit application and the Acid Rain portion of an operating

permit.'' 9

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\9\ Language in the current Sec. 72.70(b) concerning petitions

for exemption and draft, proposed, and final written exemptions is

removed because it is redundant. The requirements for exemptions are

already included in part 72.

---------------------------------------------------------------------------

An analogous provision is proposed in Sec. 72.60(a) with regard to

permitting by the Administrator. In addition, the proposal explains

that the Acid Rain requirements concerning permit applications,

compliance plans, permit content and permit shield, permit processing

and issuance, permit revision, and administrative appeals replace the

provisions in part 71 with regard to Acid Rain permit applications and

permits. The provision also states that the part 71 provisions

concerning Indian tribes, delegation of a part 71 program, affected

State review of draft permits, and public petitions to reopen a permit

for cause are not eliminated or replaced by the Acid Rain provisions

and so apply to the Acid Rain Program.

[[Page 68348]]

B. State Authority To Administer and Enforce Acid Rain Permits

The current rule provides that if a State or local agency receives

full, interim, or partial approval of an operating permits program

under title V by July 1, 1996, that agency becomes the permitting

authority for the issuance of Phase II Acid Rain permits.See 40 CFR

72.73(a). (Under the Acid Rain Program, the term ``State'' is defined

to include the 48 continguous States, the District of Columbia, and

local authorities; henceforth in this preamble, ``State'' will be used

with that meaning.) 10 The State permitting authority must issue

Phase II Acid Rain permits by December 31, 1997. If the State operating

permits program is not approved by July 1, 1996, the Administrator is

the permitting authority for Phase II Acid Rain permits and must issue

them by January 1, 1998. After a State operating permits program is

approved, the Administrator will suspend issuance of Acid Rain permits.

See 40 CFR 72.74.

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\10\ In the proposal, EPA is expanding the definition of

``State'' to include eligible Indian tribes in order to be

consistent with the treatment of Indian tribes that has been

proposed for parts 70 and 71. See 59 FR 43956 (August 25, 1994)

(proposed regulations implementing section 301(d) of the Act), 60 FR

45530 (August 31, 1995) (proposed revisions to part 70), 60 FR 20804

(April 27, 1995) (proposed part 71), and 61 FR 34213-4 (final part

71). To ensure that the approach taken to Indian tribes under part

72 is consistent with the approach that is ultimately adopted under

parts 70 and 71, today's proposal provides that ``eligible Indian

tribe'' be defined as in part 71. EPA's proposals concerning the

treatment of Indian Tribes were issued subject to public comment and

may be modified before they are issued in final form. EPA may need

to make conforming changes to today's proposal to reflect any

relevant revisions made to those proposals.

---------------------------------------------------------------------------

EPA has found that this approach should be modified. Some States

have submitted, and EPA has granted interim or full approval of,

operating permits programs that do not include all necessary Acid Rain

provisions. State permitting authorities that have approval but lack a

full Acid Rain program are not in a position to process, issue, and

otherwise administer properly Acid Rain permits. Further, some States

have indicated that they want to adopt some portions of the Acid Rain

Program (e.g., the permitting requirements for sources with Phase I and

Phase II units) 11 but not other portions of the program (e.g.,

permitting requirements for opt-in sources).

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\11\ Phase I units are subject to Acid Rain emissions reduction

requirements or emissions limitations starting in Phase I. Phase II

units are subject starting in Phase II. While only Phase I units

must have Acid Rain permits for Phase I, both Phase I and Phase II

units must have permits for Phase II. Section 72.31 is revised to

clarify that Phase II permit applications must cover all affected

units at the source.

---------------------------------------------------------------------------

Consequently, EPA proposes to revise the current rule to reflect

the variety of circumstances concerning State adoption of Acid Rain

programs. Under the proposal, a State becomes responsible for

administering and enforcing Acid Rain permits for affected sources if

it has both an operating permits program approved under part 70 and

Acid Rain regulations that are accepted by the Administrator through a

notice in the Federal Register that cover the sources. (The term

``administer'' includes all aspects of processing a permit, e.g.,

issuance, renewal, and revision.) Until these requirements are met, the

Administrator will be the permitting authority for purposes of issuing

Acid Rain permits (or the Acid Rain portion of operating permits) for

the sources.

Section 408(d) of the Act requires that Phase II Acid Rain permits

be issued for sources with Phase I and Phase II units by December 31,

1997 if a State is the permitting authority. In order to allow

sufficient time for a State to meet this statutory deadline, the

proposal states that a State must have an approved operating permits

program (whether full or interim approval) and accepted Acid Rain

regulations by January 1, 1997 or such later date as the Administrator

may set (rather than a fixed date of July 1, 1996, as in the current

rule) if the State is to be the permitting authority for the initial

Phase II Acid Rain permits. Otherwise, the Administrator will be

responsible for issuing such permits. EPA has already issued notices

identifying the status of State permitting authorities' acid rain

regulations. See, e.g., 60 FR 16127 (March 29, 1995); 60 FR 52911

(October 11, 1995); and 60 FR 62846 (December 7, 1995).

If EPA is issuing permits and, after January 1, 1997, the State

meets the requirements to become the permitting authority for Acid Rain

permits, the Administrator will cease issuing Phase II Acid Rain

permits to sources in that State. However, the Administrator will

continue to administer and enforce those Acid Rain permits that he or

she has already issued until the permits are replaced by State-issued

Acid Rain permits. The State may issue replacement permits on or before

the expiration date of the EPA-issued permits. Further, the

Administrator may retain jurisdiction over the EPA-issued permits until

any administrative or judicial appeals of them are completed.

The proposal also provides flexibility where a State has proposed a

partial Acid Rain program, e.g., where the proposed program covers

permitting of Phase I and Phase II units but not opt-in sources. In

that circumstance, the Administrator may accept the State Acid Rain

regulations, issue a notice stating that the State is the permitting

authority for Phase I and Phase II units, and retain the authority to

issue permits for opt-in sources.

If a State has become the Acid Rain permitting authority but the

Administrator determines that the State is not adequately administering

or enforcing the State Acid Rain program, the proposal sets forth a

procedure for withdrawal of that program and for administration and

enforcement by the Administrator. The procedure is modeled after, but

not identical to, the analogous procedures under parts 70 and 71.

Because the Acid Rain Program relies on a nationwide, market-based

system of allowances to achieve cost-effective SO2 emissions

reductions, it is particularly important that Acid Rain requirements be

implemented in a uniform manner by permitting authorities throughout

the U.S. In order to provide the Administrator the flexibility to

respond in a timely fashion where Acid Rain requirements are not being

properly implemented, the proposal does not fix the time frames by

which a State must address deficiencies in its program or by which EPA

becomes the permitting authority. The proposal leaves it to the

Administrator to set these time frames based on the specific

circumstances.

The proposal also includes a provision under which the

Administrator may delegate to a State all or part of his or her

responsibility to administer and enforce Phase II Acid Rain permits. If

a State does not meet the requirements for acting as the Acid Rain

permitting authority (e.g., does not yet have Acid Rain regulations

accepted by EPA), the Administrator may delegate to the State the

administration and enforcement of Phase II Acid Rain permits using

regulations established by the Administrator. This approach is

analogous to the approach in part 71.12

---------------------------------------------------------------------------

\12\ The definition of ``permitting authority'' in Sec. 72.2 is

revised to include a State permitting authority to which authority

to administer and enforce Acid Rain permits is delegated.

---------------------------------------------------------------------------

Further, the current rule does not expressly address the question

of whether the provisions of Phase I or Phase II Acid Rain permits

issued by the Administrator constitute ``applicable requirements''

under part 70. It may be argued that under title V the provisions of

federally issued Acid Rain permits are ``applicable requirements''

under part 70 and therefore must be included in State-issued operating

permits. In

[[Page 68349]]

that case, a State would have to formally incorporate, in each

operating permit for an affected source, any federally issued Acid Rain

permit.

However, title IV, which supersedes title V in Acid Rain matters,

requires all Phase I Acid Rain permits to be issued by the

Administrator. There is little purpose in requiring States to duplicate

Phase I permits in their operating permits. Moreover, any revisions of

federal Phase I permits would have to be repeated for any State

operating permits that included Phase I provisions. With regard to

federally issued Phase II Acid Rain permits, the proposal explicitly

requires that States replace the federal permit with a State-issued

Acid Rain permit by the end of the five-year effective period of the

federal permit. It is unnecessarily burdensome to require State

incorporation of the federal permit in the operating permit prior to

the federal permit's expiration. To incorporate the federal permit, the

State must essentially repeat the notice and comment process that was

used to issue the federal permit in the first place. Consequently, the

proposal states that the provisions of federally issued Phase I or

Phase II Acid Rain permits shall not be ``applicable requirements'' for

purposes of part 70.

Finally, the current Sec. 72.73(b)(2) requires State permitting

authorities to reopen Phase II Acid Rain permits by January 1, 1999

``to add'' Acid Rain NOX requirements. It is unclear whether this

language requires the reopening process to be completed or simply to

begin by that date. Under part 76, Phase II NOX compliance plans

must be submitted to permitting authorities by January 1, 1998. It

seems desirable to have a deadline (prior to Phase II) by which Acid

Rain permits will include Phase II NOX requirements. However, EPA

is also concerned that State permitting authorities have sufficient

time to process the permits. EPA therefore proposes to clarify in

Sec. 72.73(b)(2) that the reopening process and the addition of

NOX requirements must be completed by July 1, 1999.13

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\13\ A similar revision is proposed, in Sec. 72.74(c)(2), where

the Administrator is the permitting authority, except that reopening

must be completed within 6 months of submission of a complete

NOX compliance plan.

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C. Required Elements for State Acid Rain Program

The current rule sets forth the criteria for approval of the Acid-

Rain-related provisions of State operating permit programs. The basic

approach is that the State Acid Rain program is required to comply with

part 70 requirements and the additional Acid-Rain-specific requirements

listed in Sec. 72.72(b). Where the listed requirements are inconsistent

with part 70 requirements, the listed requirements must be met in lieu

of such part 70 requirements.

EPA has carefully re-examined the listed Acid-Rain-specific

requirements with an eye to minimizing the differences between State

Acid Rain permit procedures and other State operating permit

procedures. EPA recognizes that the Acid Rain permits make up a

relatively small portion of a full State operating permit program.

Minimizing the number of unique Acid Rain requirements and reducing the

number of different procedures that must be followed will reduce the

burden on States and affected-source owners and operators. In addition,

removal of Acid Rain requirements that duplicate provisions already in

part 70 will streamline Sec. 72.72 and reduce the potential for

confusion as to whether something other than the part 70 provisions is

required.

Upon re-examination of the listed requirements in Sec. 72.72(b),

EPA believes that the following requirements are unnecessary or

redundant and proposes to eliminate or revise them in order to allow

States to streamline their Acid Rain programs and permit

administration:

1. The requirement that the State permitting authority submit to

EPA any written notice of the completeness of a permit application and

a copy of each draft permit imposes an unnecessary burden. Therefore,

EPA proposes to remove the requirement. The permitting authority

already must provide EPA copies of the application and the proposed

permit under part 70, and that seems sufficient.

2. The requirement that the permitting authority include a

statement of basis in the draft permit is redundant since that is

already required under part 70. EPA therefore proposes to remove the

provision.

3. The requirement that the permitting authority provide for public

notice of the opportunity to comment and request a hearing is proposed

to be revised to be less burdensome. First, based on its experience in

processing Phase I Acid Rain permits, EPA maintains that, where a unit

is required in a draft permit simply to comply with the standard

SO2 emissions limitation (i.e., the requirement to hold allowances

covering emissions), there is little in the portion of the draft permit

on which to comment. EPA believes that this is also the case to the

extent a draft permit for a unit subject to Acid Rain NOX

requirements imposes only the standard NOX emissions limitations

under Secs. 76.5, 76.6, or 76.7, a NOX averaging plan, or a

NOX early election plan. There is little to comment on because the

requirements for compliance in these circumstances are set forth in

detail in the rule and there is little discretion involved in adopting

such permit provisions. In contrast, other compliance options, such as

Phase II repowering plans or NOX alternative emission limitations,

have more general requirements that must be crafted to fit the unique

circumstances of the unit involved. Few, if any, comments were received

on draft Phase I permits for units that were simply adopting the

standard SO2 or NOX emissions limitations or NOX

averaging plans. The Agency also found that providing notice in a

newspaper local to each source is a time consuming and expensive

process. Consequently, if a draft permit or permit revision only

requires units to meet the standard SO2 or NOX emissions

limitations or a NOX averaging plan, EPA proposes to give

permitting authorities the discretion to give notice by serving a

notice on the appropriate list of persons and omitting publication in a

local newspaper or State publication.14

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\14\ In addition, the specific references in the current rule

to part 70 provisions stating what persons must be served notice are

superfluous and so are eliminated.

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Second, the proposal explicitly provides that a State permitting

authority may, in its discretion, use the so-called ``direct final''

procedure in order to meet the requirements for issuing draft permits,

providing notice and comment, and issuing proposed permits. Under the

``direct final'' procedure (which has been used by EPA in rulemakings

and other actions under the Clean Air Act) 15 the State permitting

authority may issue, as a single document, a draft Acid Rain permit and

a proposed Acid Rain permit and provide notice of the opportunity for

public comment on the draft Acid Rain permit. In the notice the State

permitting authority states that, if no significant, adverse comment on

the draft Acid Rain permit is timely submitted, the proposed Acid Rain

permit will be deemed to be issued on a specified date without further

notice. The notice also states that, if such significant, adverse

comment is timely submitted, a proposed Acid Rain permit or denial of a

proposed Acid Rain permit will be issued and the comments addressed.

This procedure streamlines the permitting process in cases where no

adverse comment is anticipated. While EPA believes that the current

rule

[[Page 68350]]

does not bar using this streamlined procedure, the proposed rule makes

explicit the option to use the procedure.16

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\15\ See, e.g., 60 FR 18462 and 18472 (April 11, 1995).

\16\ For the same reasons, the proposed rule includes an

analogous provision in subpart F, which sets forth the Acid Rain

permit issuance procedures when the Administrator is the permitting

authority.

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4. The requirements that the permitting authority submit a copy of

the proposed permit for review by the Administrator and affected States

and incorporate changes resolving objections to the proposed permit are

redundant since part 70 already imposes these requirements. These

provisions in Sec. 72.72(b) are unique only to the extent that they

specifically refer to issuance or denial of Acid Rain permits. EPA

believes that such reference is unnecessary because the authority to

deny a permit where basic requirements (e.g., meeting the applicability

criteria for the Acid Rain Program) are not met is obvious. EPA does

not see any reason for addressing the possibility of permit denials

differently in part 72 than in part 70 and part 71.

5. The requirement that invalidation of the Acid Rain portion of

the operating permit not affect the remaining provisions of the permit

and vice versa is redundant. Part 70 already requires that invalidation

of any operating permit provision not affect any other operating permit

provisions.

6. The limitation on the filing of State administrative or judicial

appeals of an Acid Rain permit to no more than 90 days from the

issuance of the permit to be appealed makes appeals of Acid Rain

provisions different from appeals of any other aspect of an operating

permit. Under part 70, the availability of and procedures for

administrative appeals are left entirely to the States; there are no

mandated time limitations on filing such appeals. With regard to

judicial appeals, part 70 provides that appeals may be filed after a

fixed period (which may not exceed 90 days) if the appeal is based

solely on grounds arising after the deadline. EPA has proposed to

lengthen the maximum period under part 70 from 90 to 125 days. 59 FR

44460, 44516 (August 29, 1994). EPA sees no reason for treating appeals

of Acid Rain provisions differently than appeals of other permit

provisions and is concerned that the different appeal periods may

engender confusion. Having different appeal periods could result in

different parts of the same operating permit having different deadlines

for filing appeals. The proposal eliminates the limitation on Acid Rain

appeals.

7. The requirement that a permitting authority give the

Administrator notice of administrative or judicial orders relating to

an Acid Rain permit is retained. The proposal removes language

indicating that, after issuance of such an order, the Administrator

will review and may veto the Acid Rain permit under the procedures for

reviewing proposed permits under Sec. 70.8. The language was intended

to provide for EPA review where, for example, an Acid Rain permit that

had already undergone EPA review under Sec. 70.8 was then significantly

altered on appeal. Upon reconsideration, EPA concludes that this

approach in the current Sec. 72.72 is confusing since it may put into

question whether an ostensibly final permit becomes a proposed permit

when there is a State determination (e.g., a State court order)

modifying the permit. This approach is also unnecessary since the

Administrator already has the authority to reopen permits for cause,

which authority is available in the event of such a State determination

or interpretation.17

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\17\ For the same reasons, an analogous provision in

Sec. 72.80(e) is also removed.

---------------------------------------------------------------------------

8. The requirement that State administrative appeals not result in

the stay of any provisions that could not be stayed under part 78 is

proposed to be removed for several reasons. First, as discussed below

(in section VII of this preamble), the provision on stays in part 78 is

eliminated because, under current case law, a permit appealed under

part 78 is not a final agency action, and cannot be implemented,

pending the administrative appeal. Further, in reviewing State

operating permit programs, EPA has found that States have a variety of

administrative appeals processes. In many States the administrative

appeal precedes the issuance of a final permit and so the stay

provision in the current part 72 is meaningless. In addition, the

provision bars stays of requirements in the permit (i.e., allowance

allocations, the standard Acid Rain requirements, monitoring and

reporting requirements, and the certificate of representation) that are

imposed, under part 72 and other Acid Rain rules, independently from

the permit. Even if a source has no permit, the source must meet these

requirements. In short, the stay provision has little practical effect.

9. The requirements that State permitting authorities

``coordinate'' with utility regulatory authorities and evaluate the

sufficiency of fees supporting the State acid rain program are proposed

to be removed as unnecessary. The relationship between State agencies

is best left to the States, and part 70 fully addresses issues

concerning fees.

In reconsidering the requirements for State operating permit

programs, EPA has become aware of another issue concerning State

programs. The current rule requires that a permitting authority issue,

for each affected source, only one Acid Rain permit covering all

affected units at that source. EPA received comment that, in a few

cases, States have historically issued separate permits to units that

are at the same source but that were constructed at different times.

The States plan to continue separate permitting of the units under

their operating permits programs. Rather than requiring State

permitting authorities to restructure their permitting of such sources,

EPA proposes to give permitting authorities the discretion to allow

separate Acid Rain permit applications for, and thus to issue separate

Acid Rain permits to, the units at the source. However, this provision

does not change the designated-representative requirements for the

units: all units at the source must still have the same designated

representative and, if applicable, the same alternate designated

representative.

A large number of State permitting authorities have already adopted

Acid Rain regulations consistent with the current provisions of part

72. The most efficient and most frequently used method of State

adoption of Acid Rain regulations has been incorporation of part 72 by

reference. The part 72 rule changes proposed today are primarily aimed

at streamlining Acid Rain permitting (whether EPA or the State is the

permitting authority). EPA therefore anticipates that State permitting

authorities will want to adopt the final revisions relatively soon

after promulgation. However, EPA recognizes that revising State

regulations, even when accomplished through incorporation by reference

of the revised part 72, can be a time consuming process. Moreover,

State permitting authorities are required to issue initial Phase II

Acid Rain permits by December 31, 1997. None of today's proposed

revisions are so fundamental that a State permitting authority with

Acid Rain regulations consistent with the current part 72 should not

start or even complete the process of issuing the Phase II permits

before revising its Acid Rain regulations to conform to today's

revisions. In order to ensure that States have both sufficient

authority to issue Phase II permits and sufficient time to revise their

Acid Rain regulations, EPA will continue to accept State Acid Rain

[[Page 68351]]

rules that conform with the current part 72 until 2 years after the

date on which the final revisions are promulgated. Starting on the date

2 years after the promulgation of the final revisions, EPA expects all

State Acid Rain regulations to incorporate the revisions.

EPA notes that many States have not added to their Acid Rain rules

the provisions of part 74 (opt-in program) and part 76 (NOx compliance

plans and emissions limitations), which were issued relatively recently

in April 1995. Further, EPA has proposed additional part 76 provisions

setting Phase II NOx emissions limitations and expects to issue final

provisions by January 1, 1997. States may want to consider coordinating

adoption of the final revisions based on today's proposal with adoption

of the provisions of parts 74 and 76.

III. Part 72: Miscellaneous Permitting Matters

In addition to the revisions discussed above, EPA proposes a number

of revisions of sections of part 72 concerning matters such as

designated representatives, compliance plans, federal procedures for

permit issuance and revision, and confirmation reports on verified

savings from energy conservation and increased unit efficiency

measures. The primary purpose of these proposed changes is to

streamline the Acid Rain rules and reduce the administrative burden on

owners and operators of affected units.

A. Definitions

In addition to the definition revisions discussed elsewhere in this

notice, the Agency proposes the following revisions.

The definition of ``Acid Rain emissions limitation,'' for purposes

of sulfur dioxide emissions, is revised to make complete the list of

statutory provisions under which affected units may be allocated

allowances. Section 404(h), which is inadvertantly left out of the

current definition, is added. The definition of the term, for purposes

of nitrogen oxides emissions, is revised to remove references to

regulations implementing section 407 of the Act. The NOx Acid Rain

regulations in part 76 became final on May 23, 1995 and so the

definition is revised simply to cite part 76. Analogous changes are

made elsewhere in part 72 to replace general references to regulations

under section 407 by specific references to part 76 or sections of part

76.

The definition of ``coal-fired'' is revised to exclude the

superfluous reference to part 73 and to correct the reference to the

regulations implementing section 407 of the Act (i.e., part 76) to

reflect the fact that part 76 includes its own definition of ``coal-

fired.''

The definition of ``dispatch system'' is eliminated. In light of

the detailed provisions concerning dispatch system in section 72.33,

the definition is superfluous and potentially confusing.

The definition of ``permitting authority'' is revised to omit some

superfluous language and to reference part 70, rather than refering

generally to the regulations promulgated under title V. Such general

references in other provisions of part 72 are also changed to specific

references to parts 70 and 71 as appropriate.

The definition of ``submit or serve'' is revised in order to allow

documents, information, or correspondence to be provided to the

Administrator or any State permitting authority using any service of

the U.S. Postal Service or any equivalent means of dispatch and

delivery. The requirement in the current rule that such delivery be

accomplished using only certified mail or an equivalent service is

eliminated. Based on its experience in operating the Acid Rain Program,

EPA has found that the certified-mail requirement is not necessary and

may be burdensome on private parties.

B. Designated Representative

The current rule requires the selection of one designated

representative for each affected source and allows the selection of one

alternate designated representative per source. EPA has received

comment requesting that under certain limited circumstances a second

alternate designated representative be allowed. According to the

commenter, in general, the current rules give operating companies the

flexibility of having a designated representative at the upper

management level and an alternate who is closer to the plant operations

level in the company. Allegedly, this flexibility is in effect denied

to operating companies that are part of a holding company if the

holding company plans to use a NOx averaging plan under part 76 to

comply with the applicable Acid Rain NOx emission limitation.

Under Sec. 76.11, units that are subject to the standard NOx

emission limitations (in Secs. 76.5, 76.6, or 76.7), are under the

control of the same owner or operator, and have the same designated

representative may average their NOx emissions through a

compliance plan approved by the permitting authority. The detailed

requirements for determining whether units are in compliance with the

plan are set forth in Sec. 76.11. The commenter states that it is one

of several operating companies in a holding company and that all of the

operating companies intend to participate in a holding-company-wide

NOx averaging plan, which under Sec. 76.11 requires the selection

of a single designated representative for the entire holding company.

According to the commenter, that designated representative must, as a

practical matter, be someone at the holding-company management level.

Since each operating company can select only one alternate, each

operating company will be unable to have a designated representative or

alternate at both the management and the operations levels of the

operating company. Allegedly, this is important because each operating

company operates relatively independently, reflecting the fact that

each is in a different State and is subject to regulation by a

different utility regulatory authority.

In order to accomodate this limited circumstance where additional

flexibility may be needed, EPA proposes to allow the selection of a

second alternate designated representative in this circumstance. The

Agency requests comment on the need for this flexibility in this case.

The current rule also establishes procedures for the selection of a

designated representative and an alternate. Using these procedures, all

Phase I units and many Phase II units have selected designated

representatives. In addition, alternates were originally selected or

were added later in some cases, and some units have changed their

representatives. Based on this experience with the prescribed

procedures, EPA proposes to simplify the procedures and reduce the

burden they impose on owners and operators. The Agency maintains that

this can be done without negatively impacting the rights of minority or

other owners.

In particular, Secs. 72.20(c) and 72.24(a)(5) require that whenever

a designated representative or alternate is originally selected or

changed, notice must be provided daily for one week in a newspaper of

general circulation where the source is located or in a State

publication. The Agency has learned that this provision of newspaper

notice is often expensive and can be particularly cumbersome where a

single designated representative or alternate is selected or changed

for a group of units spread over a relatively wide geographic area

(e.g., a State) or where local newpapers are weekly rather than daily.

While some notice of designated-representative selection seems

desirable, EPA believes that the current rule is

[[Page 68352]]

unduly burdensome. EPA proposes to revise the rules to require only one

notice in the newspaper (i.e., notice for one day), rather than daily

notices for a week. Further, since the designated representative is the

primary person representing the owners and operators and is responsible

for all actions by any alternate, it seems unnecessary to require

notice of selection or change of an alternate.

EPA also proposes a minor correction of Sec. 72.25. That section

currently provides that the Administrator will rely on a certificate of

representation until a superseding one is ``submitted.'' 40 CFR

72.25(a). However, the Administrator will be unaware of any superseding

certificate until he or she receives it. Further, Sec. 72.20(b) states

that a certificate of representation is binding upon receipt of the

complete certificate by the Administrator. Section 72.25 is therefore

revised to provide that a certificate is relied on until ``receipt'' of

a superseding certificate.

C. Compliance Plans

l. Submission of Substitution and Reduced Utilization Plans

Sections 72.41 and 72.42 currently state that a new substitution

plan or reduced utilization plan may be submitted not later than 90

days before the allowance transfer deadline. A submission must be made

by both the Phase I unit and its prospective substitution or

compensating unit so that the plan will be reflected in their Acid Rain

permits. However, there are other provisions of the rules that affect

when such plans may be approved and take effect and that must be

considered in deciding when to submit a plan. An affected unit must, as

of the allowance transfer deadline, hold sufficient allowances to cover

its emissions for the prior year. Consequently, the status of a unit as

an affected unit for a given year (e.g., in Phase I, its status as a

substitution unit or a compensating unit) must be determined as of the

allowance transfer deadline. A new compliance plan designating a new

substitution or compensating unit for a Phase I unit must be approved

and active by the allowance transfer deadline in order to be effective

for the year to which the allowance transfer deadline applies.

A new plan may include both a Phase I unit and a prospective

substitution or compensating unit at a source that has no Phase I units

and so lacks a Phase I permit. Since each unit must have a Phase I

permit that includes the plan, the plan must be added to the Phase I

unit's existing permit and included in a new Phase I permit for the

source with the substitution or compensating unit. Because the Agency

has up to 6 months to act on a new permit, the Phase I unit's plan and

the source's new permit application that includes the plan should be

submitted at least 6 months before the allowance transfer deadline.

Later submission will not ensure approval of the plan in time for use

for the year to which that allowance transfer deadline applies.

If all the units in a new plan are at sources that already have

Phase I permits, then the plan can be added to both the Phase I unit's

permit and the prospective substitution or compensating unit's permit

through a permit revision. If the permit modification procedures are

used, the Agency still has up to 6 months to act. However, if the fast-

track amendment procedures are used, the Agency has 60 days from the

start of the public comment period to act. In the latter case, the

submission deadline of 90 days prior to the allowance transfer deadline

provides sufficient time for approval of the plan.18

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\18\ Section 72.30(b)(3) references the deadlines in subpart D

of part 72 and part 76 for applying for compliance plans. The

provision is redundant and is therefore removed.

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In order to ensure that designated representatives consider the

procedures and timing that must be followed in submitting new plans,

EPA proposes to revise Secs. 72.41(b)(3) and (c)(4). The revisions

state that new plans must be submitted no later than 6 months prior to

the allowance transfer deadline but that, if the fast-track amendment

procedures are available, submission must be no later than 90 days

before the allowance transfer deadline.

2. Repowering Extension Plans

The current Sec. 72.44 includes provisions concerning failed

repowering projects. The regulation requires that, if efforts to

complete and test the project are terminated prior to construction or

start-up testing, the designated representative must demonstrate to the

satisfaction of the Administrator that the efforts were in good faith.

Similarly, if the project is properly constructed and tested but is

unable to achieve emission reductions specified in the repowering

extension plan, a demonstration must be provided. Under the current

Sec. 72.81(a), determinations concerning failed projects must be

processed as permit modifications. However, the interaction between the

demonstration requirements in the current Sec. 72.44(g) and the

procedures in Sec. 72.81 is unclear, particularly when the State

permitting authority issued the permit containing the repowering

extension plan and is therefore handling the permit modifications.

EPA proposes to revise Sec. 72.44(g) to clarify the interaction of

the substantive and procedural requirements concerning failed projects.

Under the revisions, the designated representative submits to the

permitting authority a permit modification in which he or she makes the

necessary demonstrations. The Administrator determines whether the

demonstrations have been made. Where the State is the permitting

authority, the State acts on the permit modification consistent with

the Administrator's determination.

D. Federal Permit Issuance

1. The current Sec. 72.60(b) requires that the Administrator issue

or deny an Acid Rain permit within 6 months of receipt of a complete

permit application. However, Sec. 72.74(b) provides that initial Phase

II permits, for which applications are due by January 1, 1996, must be

issued by the statutory deadline of January 1, 1998 if they are issued

by the Administrator. EPA proposes to revise Sec. 72.60(b) to provide

that deadline in Sec. 72.74(b) applies, rather than the 6-month

deadline, to any initial Phase II permits issued by the Administrator.

2. The current Sec. 72.61 provides that a permit application is

deemed complete after 30 days in the absence of notification by the

Administrator that it is incomplete. When additional information is

requested by the Administrator, the designated representative has at

least 30 days to respond. EPA proposes to revise this section to make

it consistent with the currently different completeness provisions of

part 71 (and part 70) in order to avoid having two types of

completeness procedures. Under the revisions, automatic completeness

occurs after 60 days from receipt and additional information must be

submitted within a reasonable period specified by the Administrator. In

addition, language in parts 70 and 71 is added to this section

requiring designated representatives to provide supplementary

information when they become aware that relevant information was not

submitted or incorrect information was submitted.19

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\19\ This language in parts 70 and 71 is also added to

Sec. 72.80 with regard to permit revisions.

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3. As discussed above, EPA is proposing to revise the provisions

for Acid Rain permitting by States in order to allow, for certain types

of draft permits, service of notice on a list of persons and foregoing

of newspaper

[[Page 68353]]

notice. For the same reasons, EPA proposes a similar type of revision

for federal Acid Rain permitting. The Administrator may provide Federal

Register notice and notice for a list of persons and omit newspaper

notice where the only Acid Rain emissions limitations in the draft

permit are the requirements to hold sufficient allowances for SO2

or to comply with NOX emission limitations under Secs. 76.5, 76.6,

76.7, or 76.11.

Moreover, the list of persons required to be served notice of draft

and final permits under the current rule is different than the list of

persons required to be served under parts 70 and 71. This difference

complicates the notice process without any significant benefit. EPA

proposes to revise the list of persons for required service of

federally-processed draft and final permits to be consistent with parts

70 and 71.20 For example, parts 70 and 71 do not require service

on the State or local utility regulatory authorities with jurisdiction

over the unit involved or the owners of the unit. No utility regulatory

authorities commented on any of the Acid Rain permits or permit

revisions that have been issued by EPA for Phase I. The proposal

therefore eliminates such authorities from automatically-required

service.21 Any utility regulatory authorities that want to receive

notice of draft and final permits will still have the option of

requesting to be treated as an interested person and thereby receiving

notice.

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\20\ The same change is proposed for the list of persons on

which requested fast-track amendments submitted to the Administrator

must be served under Sec. 72.82. Where requested fast-track

amendments are submitted to the State as the permitting authority,

the proposal provides that the list of persons is the same persons

on which the State permitting authority must serve notice of draft

permits under the State operating permits program. Further, since

parts 70 and 71 require service of notice on ``affected States'' and

include a definition of that term, today's proposal includes a new

definition that adopts the ``affected State'' definition in part 71.

\21\ The proposal therefore also eliminates the requirement to

identify such authorities in submissions to EPA (e.g., in a source's

certificate of representation).

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E. Permit Revision

1. EPA proposes to make minor revisions to remove specific

reference to part 70 procedures from, and to add specific references to

Sec. 72.80 in, Sec. 72.81 concerning permit modifications.

2. EPA proposes to lengthen the deadline by which a State

permitting authority must act on a fast-track modification. Under the

current rule, the Administrator or State permitting authority must act

within 30 days of the close of the 30-day comment period. State

permitting authorities must handle many more permits covering a broader

range of types of sources and emission limitations than EPA's Acid Rain

Division, which handles only Acid Rain permits for the Administrator.

EPA is concerned that the 30-day deadline for States to act on a fast-

track modification may be unrealistic in light of their other,

significant responsibilities. To put the 30-day deadline in

perspective, States under title V can take up to 18 months to issue

permits or make significant permit modifications. Under today's

proposal, the 30-day deadline will continue to apply to the

Administrator but a 90-day deadline from the end of the comment period

will apply to State permitting authorities.

3. EPA proposes to remove and replace certain confusing language at

the end of the fast-track modification provisions concerning review by

the Administrator and affected States. The current language makes fast-

track modifications subject to the same review as significant permit

amendments. The proposal states this more directly. Such review is

appropriate since fast-track modifications can involve important

changes to a permit.

4. The current rule concerning administrative permit amendments

relies heavily on, and cites, the part 70 administrative permit

amendment procedures. These part 70 procedures are currently the

subject of an on-going rulemaking in which extensive revisions have

been proposed. See 59 FR 44475-79. EPA proposes to remove the citations

to part 70 and to set forth in Sec. 72.83 itself the procedures for

administrative amendments to Acid Rain permits. EPA believes that the

administrative amendment procedures currently applicable to Acid Rain

permits are simple and, except as discussed below, should not be

substantively changed.

While the proposal continues to require action by the permitting

authority within 60 days of receipt, the period for acting on one

potentially very complicated administrative amendment, i.e., the

addition of an alternative emissions limitation demonstration period

for NOX, is lengthened to 90 days. Before implementing the

addition of an alternative emissions limitation demonstration period, a

permitting authority must determine whether the requirements of

Sec. 76.10 have been met. The designated representative must provide

extensive information, e.g., showing that the unit has a properly

installed and operated NOX emission control system designed to

meet the standard NOX emission limitation (under Secs. 76.5, 76.6,

or 76.7), describing why the unit cannot meet the standard emission

limitation, and outlining the testing and procedures to be undertaken

to determine the maximum emission reduction that can be achieved with

the installed system. EPA maintains that 60 days will likely be

insufficient time, particularly for State permitting authorities, to

evaluate this information and, if the requirements of Sec. 76.10 are

met, grant a requested alternative emissions limitation demonstration

period and that 90 days is a more reasonable deadline.

The proposal also adds a provision explicitly allowing the

permitting authority to make administrative permit amendments (other

than the addition of an alternative emission limitation demonstration

period) on its own motion. This procedure may be used to correct minor

errors in a permit that come to the attention of the permitting

authority.

Also added to Sec. 72.83 are provisions in the current part 70 that

allow immediate implementation of administrative permit amendments that

meet applicable requirements and that eliminate review of such

amendments by the Administrator or affected States. This adds directly

to part 72 provisions that the current Sec. 72.83 makes applicable by

reference to part 70.

5. The current rule concerning permit reopenings relies heavily on,

and cites, part 70 reopening procedures. EPA proposes to eliminate the

references and set forth in Sec. 72.85 the full procedures. Consistent

with the current part 70 provisions, the proposal states that reopening

for cause may occur when: Additional Acid Rain requirements become

applicable; there is a material mistake in the permit; inaccurate

statements were made in establishing a permit term or condition; or a

permit revision is necessary to assure compliance with the Acid Rain

Program.

F. Reduced Utilization Accounting

Under the current rule, Phase I units must account for any

underutilization. A few revisions are proposed with regard to this

accounting.

1. The current rule allows a designated representative to submit an

identification of dispatch system in order to change a unit's dispatch

system from what is listed in the NADB, which indicates the operator of

each unit. A dispatch-system identification must be submitted by

January 30 of the first year for which the new dispatch system is to

take effect. Traditionally, there have been relatively few changes in

the operator and the dispatching of utility

[[Page 68354]]

units. However, in light of increased competition in the electric

industry and the potential of future restructuring of the industry, the

Agency is concerned that changes in owners and operators and in

dispatching of units may occur more frequently and at times that make

it impossible to meet the January 30 deadline. EPA therefore proposes

to give the Administrator the discretion to grant exemptions from that

deadline in order to allow late submissions.

2. The current rule sets forth procedures for claiming kilowatt

hour savings from energy conservation measures or heat rate reductions

from improved unit efficiency measures and using the resulting heat

input reductions to reduce the surrender of allowances to account for

reduced utilization of Phase I units. In the annual compliance

certification reports submitted by March 1, a designated representative

may include estimated savings from energy conservation or estimated

heat rate reductions from improved unit efficiency measures for the

prior year. If any such estimates are included in the annual compliance

certification report, the designated representative must submit a

confirmation report by July 1 that provides and supports the verified

amounts.

The current language in Sec. 72.91(b)(1)(iii) concerning the

methods for supporting the verified amounts of kilowatt hour savings,

heat rate improvement, and resulting heat input reductions needs some

clarification.22 The purpose of the provision is to provide two

alternative approaches to verification: documentation that may follow

the EPA Conservation Verification Protocol; or certification by the

appropriate State utility regulatory authority. The current provision

could be read to require that only one of these approaches be used for

all estimated savings and heat input reductions so that, for example,

if certification is to be used, it must be used for all the estimates.

EPA proposes to revise the provision to make it clear that there is

flexibility to use documentation with regard to improved unit

efficiency measures or some energy conservation measures and to use

certification for other measures.

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\22\ The verification process, found in Sec. 72.91(b), is

incorrectly cross-referenced in Sec. 72.43(b)(2)(iii)(B) of the

current rule. Today's proposal corrects the reference. In addition,

certain typographical errors in Sec. 72.91(b) (e.g., incomplete

reference to ``improved unit efficiency measures'') are corrected.

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3. The current regulatory provisions concerning heat input

reductions due to measures that reduce a unit's heat rate need

clarification and revision. A measure that reduces a unit's heat rate

may be treated as a supply-side energy conservation measure by another

unit or as an improved unit efficiency measure by the unit at which the

measure is implemented. Over a given period of time, a number of

specific measures may be implemented at a unit to reduce its heat rate.

However, these measures may be offset by reductions in generation

efficiency at the same unit resulting from other factors, e.g., from

the aging or changed operations of the unit. In that case, even though

each measure may, in itself, reduce the heat rate of the unit below

what the heat rate would otherwise have been, the net effect of all the

measures on the unit's heat rate will be less than the sum of the

reductions attributed to each measure.

It is the net effect of these measures on the unit's heat rate that

should be treated as accounting for reduced utilization. Consequently,

EPA proposes to add a provision that puts a ceiling on the total heat

input reductions that may be claimed for all measures that reduce a

given unit's heat rate, whether the measures are treated as energy

conservation or improved unit efficiency measures. Under the proposal,

the total verified heat input reductions attributed to such measures

may not exceed the difference between the kilowatt hour generation

attributed to the unit for the calendar year times the difference

between the unit's heat rate for 1987 and its heat rate for the

calendar year. This ensures that heat input reductions cannot exceed

the heat input reductions attributable to net heat rate improvement

since the end of the base period (i.e., 1985-1987). Heat rate

improvements made up through 1987 are already reflected in the baseline

utilization and so cannot be used to account for underutilization of a

unit since the base period. See 58 FR 60950, 60961 (November 18, 1993).

In light of this ceiling on heat input reductions claimed for

energy conservation measures improving generation efficiency (as well

as for improved unit efficiency measures), EPA sees no need to burden

State utility regulatory authorities with the verification of claimed

reductions from this limited category of energy conservation measures.

EPA will instead review the verification presented by designated

representatives and will compare the claimed heat input reductions to

the ceiling. Consequently, EPA proposes to remove the option of

verification by State utility regulatory authorities of claimed

reductions from energy conservation measures improving generation

efficiency.

4. The current rule provides that, if the total verified amount of

heat input reductions in the confirmation report differs from the total

estimated amount in the annual compliance certification report, the

confirmation report must calculate the number of allowances, if any, to

be surrendered or returned as a result. EPA maintains that the

provision concerning calculation of allowances to be returned needs

clarification and revision.

a. Under the current rule, if the total verified heat input

reductions exceed the total estimated heat input reductions, returned

allowances are to be calculated using a specified formula in

Sec. 72.91(b)(4) based on the difference between the verified and

estimated amounts. Section 72.91(a)(7) sets a limit on the total amount

of ``plan reductions'' (i.e., offsets to underutilization that are

attributed to energy conservation, improved unit efficiency, sulfur-

free generation, and compensating units). A Phase I unit's plan

reductions minus any compensating generation that it provides as a

compensating unit cannot exceed the Phase I unit's baseline minus its

actual utilization. The purpose of this limitation is ``to prevent plan

reductions from one Phase I unit from being used to offset the

underutilization of another Phase I unit that has no reduced

utilization plan.'' 58 FR 60962. This purpose applies equally whether

the plan reductions involved reflect estimated offsets from

conservation and improved unit efficiency or verified offsets. The

confirmation process simply replaces estimated with verified offset

amounts and corrects for any differences; it is not intended to allow

greater offsets than if the verified offset amounts had been available

when the annual compliance certification report was submitted.

The simplest way to ensure that designated representatives

understand that this limitation applies is to limit the number of

allowances that are to be returned to the total number of allowances

that were deducted from the unit's Allowance Tracking System account

for underutilization based on the annual compliance certification

report. EPA proposes to add language (in Sec. 72.91(b)(4)(iv)) setting

forth this limitation. To the extent allowances were deducted based on

the annual certification report, then those allowances represented

underutilization of the unit (i.e., a positive difference between the

unit's baseline and its actual utilization after accounting for all

offsets). If allowances in excess of the amount of that allowance

deduction were returned, then verified offsets from

[[Page 68355]]

conservation or improved unit efficiency would be used, in effect, to

offset some other unit's underutilization.

b. Under the current rule, if the total verified offsets are less

than the total estimated offsets, surrendered allowances are to be

calculated using the absolute value of the formula specified for

returning allowances in Sec. 72.91(b)(4). EPA has found that this

provision concerning the allowances to be surrendered is not correct in

all cases and should be revised.

Under Secs. 72.91 and 72.92, allowance surrender is determined

initially on a dispatch-system-wide basis so that underutilization of

one Phase I unit in the dispatch system may be offset by

overutilization of another Phase I unit in that dispatch system. Once

it is determined that allowances must be surrendered for the dispatch

system, each Phase I unit's share of the surrender is calculated. The

approach in the current rule is accurate if the Phase I unit had to

surrender allowances based on the annual compliance certification

report. In that case, the unit's underutilization was not offset

completely by other Phase I units and any overstatement of offsets in

the estimates used in the annual compliance certification report must

result in additional surrender of allowances by the unit.

In contrast, if the Phase I unit did not have to surrender

allowances based on the annual compliance certification report, the

overstatement of offsets in the estimates could be offset by

overutilization of other Phase I units. The provisions of the current

Sec. 72.91(b)(5) do not take account of that possibility.

EPA proposes to revise Sec. 72.91(b)(5) to correct this problem and

ensure that the confirmation process does not result in the surrender

of more allowances than if the verified amounts for conservation or

improved unit efficiency offsets had been available when the annual

compliance certification report was submitted. The revision provides

that each Phase I unit that used estimated conservation or improved

unit efficiency offsets must recalculate its adjusted utilization using

the verified amounts and then that the allowance surrender formula in

Sec. 72.92(c) must be reapplied using the recalculated adjusted

utilizations. To the extent this results in greater allowance surrender

than the surrender based on the annual compliance certification report,

the difference must be surrendered.

c. Under the current rule, the designated representative must

include in the confirmation report calculations of any change in the

excess emissions that were previously determined based on the annual

compliance certification report. EPA has decided that this is an

unnecessary burden to impose on the designated representative. The

current rule does not require the designated representative to

calculate in the annual compliance certification report the amount of

any excess emissions. Moreover, under the revisions of part 77

discussed below, the offset plan submitted by the designated

representative of a unit with excess emissions will also not be

required to state the amount of excess emissions.

Consistent with this approach, EPA proposes to eliminate the

requirement that the confirmation report calculate the impact of the

verified offsets on excess emissions. Instead, Sec. 72.91(b)(6) and (7)

are revised to require the Administrator to determine the amount of

excess emissions (if any) that would have resulted if the verified,

rather than estimated, offsets had been used to make deductions from

the allowances in the unit's compliance subaccount as of the allowance

transfer deadline. Further, if the resulting excess emissions differ

from the amount determined based on the estimated offsets, the

Administrator must determine whether additional offset allowances must

be deducted and penalty payments must be made or whether allowances and

penalty payments must be returned.

5. The current Sec. 72.95 sets forth the formula for making

allowance deductions for each year that a unit is subject to the Acid

Rain emissions limitations for SO2. Although the formula does not

specifically refer to allowance deductions with respect to substitution

or compensating units, Secs. 72.41(d)(3) and (e)(1)(iii)(B) and

72.43(d)(2) expressly require such deductions under certain

circumstances. In order to make the formula consistent with those

express deduction provisions, EPA proposes to revise the formula to

include those deductions, which are required in any event.

IV. Part 73: Allowances

A. Revision of Table 2 Allowances

EPA proposes to revise the allowances of certain units on Table 2

of Sec. 73.10(b).

l. Allowance Determinations Remanded to EPA

Section 405(c) of the Act establishes allowances in Phase II for

smaller units (under 75 MWe nameplate capacity) with higher emissions

(over 1.2 lb/mmBtu). Paragraph (c)(1) of the section specifies the

formula for calculating basic allowances for units owned by larger

operating companies (with capacity of at least 250 MWe). Paragraph

(c)(2) specifies the formula for basic allowances for such units owned

by smaller operating companies (with capacity of less than 250 MWe).

Paragraph (c)(3) provides special basic allowances for such units that

are owned by larger operating companies (with capacity greater than 250

MWe and less than 450 MWe) that serve fewer than 78,000 customers.

Paragraph (c)(4) provides bonus allowances for units under paragraph

(c)(1) for the period 2000 through 2009. Paragraph (c)(5) provides

special basic allowances to units under paragraph (c)(1) in utility

systems that have units with high costs for retrofitting flue gas

desulfurization devices.

The language in section 405(c) raises questions of how to measure

utility capacity or size for purposes of applying the various

paragraphs in the section. Paragraphs (c)(1) and (2) state that they

apply to units of a ``utility operating company whose aggregate

nameplate fossil fuel steam-electric capacity is'' of specified

magnitudes. 42 U.S.C. 7651d(c)(1) and (2). In contrast, paragraph

(c)(3) states that it applies to units of ``a utility operating company

with, as of December 31, 1989, a total fossil fuel steam-electric

generating capacity'' within a specified range of megawatts and with

fewer than 78,000 electrical customers.

EPA proposed and finalized Phase II allowances allocations based on

its interpretation that, despite the language differences among these

statutory phrases, all of the phrases incorporate the same approach for

defining a utility operating company's capacity. In applying all the

provisions of section 405(c), EPA summed the nameplate capacity of the

generators operated by the unit's operating utility to determine that

utility's capacity. See 57 FR 29940, 29953-54 (July 7, 1992); and 58 FR

15662 and 15697.

Two utilities challenged EPA's allowance allocations to their units

under section 405(c). Madison Gas & Electric Co. (Madison Gas)

challenged EPA's position that only the nameplate capacities of the

units operated by a given utility should be considered in determining

utility capacity, rather than instead considering the nameplate

capacity of the units owned in whole or in part by the utility. The

City of Springfield, Illinois, City Water, Light and Power (City of

Springfield) challenged EPA's use of nameplate capacity, rather than

summer net dependable capability, as the measure of generating capacity

under section

[[Page 68356]]

405(c)(3). Madison Gas and City of Springfield petitioned for judicial

review of their allowance allocations. On May 27, 1994, the U.S. Court

of Appeals for the Seventh Circuit remanded to EPA the allowance

allocations for these utilities in order for the Agency to reconsider

these two issues concerning utility capacity. Madison Gas & Electric v.

U.S. EPA, 4 F.3d 529 (7th Cir. 1994).

Madison Gas argued, in its comments on EPA's original allowance

allocations, that the language of section 405(c)(1) and (2) compel EPA

to measure utility capacity based on the utility's ownership of

capacity in any unit, including partially owned units. Sections

405(c)(1) and (2) apply to units owned by a utility ``whose aggregate

nameplate fossil fuel steam-electric capacity'' is of a specified

magnitude. 42 U.S.C. 7651d(c)(1) and (2). According to Madison Gas, the

use of the word ``whose'' in this context means that the capacity must

be owned by the utility. In contrast, EPA read the word ``whose'' to

mean that the capacity must be operated by the utility.

EPA now believes that this language in section 405(c)(1) and (2)

can support either interpretation. Further, EPA has identified at least

two other utilities whose allocations would be affected by the adoption

of Madison Gas's interpretation. EPA is concerned that adopting Madison

Gas's interpretation and reducing, at this late date, the number of

allowances allocated to these other utilities would disrupt the

compliance planning already undertaken for these units. Therefore, on

reconsideration, EPA believes that a fair and appropriate approach is

to read the language in section 405(c)(1) and (2) to mean either

aggregate nameplate capacity owned by a utility operating company or

aggregate nameplate capacity operated by a utility operating company

and to apply the most favorable reading to the utility involved. EPA

believes that permitting the alternative interpretations is acceptable

in light of the ambiguity of the statutory language. Moreover, this

gives the three utilities affected by this issue the opportunity to

claim and receive the most favorable allowance allocation available

under these provisions, with little practical effect on other

utilities.

From data submitted by Madison Gas in its comments on the original

allowance allocations, Madison Gas, as of 1989, owned more than 250 MWe

of capacity. Madison Gas recognized that the interpretation of section

405(c) (1) and (2) that it favors results in it receiving more

allowances each year during 2000 through 2009 but fewer allowances each

year thereafter and fewer total allowances. EPA therefore proposes to

apply Madison Gas' interpretation of the provisions and to provide

allowances to Madison Gas' Blount Street plant in Wisconsin as follows:

unit 7, 116 unadjusted basic allowances each year in perpetuity under

section 405(c)(1) and 1374 bonus allowances each year during 2000-2009

under section 405(c)(4); unit 8, 473 unadjusted basic allowances and

716 bonus allowances; and unit 9, 633 unadjusted basic allowances and

629 bonus allowances. These will be in lieu of the allowances for the

units in the current Table 2.

Two other utilities are potentially affected by the interpretation

of the utility-size language in section 405(c) (1) and (2). If the

language is interpreted to refer to total owned capacity, Potomac

Edison Company's R P Smith unit 9 in Maryland will be provided 320

unadjusted basic allowances under section 405(c)(1) and 354 bonus

allowances under section 405(c)(4). Interpreting section 405 as

referring to operated capacity, the unit receives 386 unadjusted basic

allowances under section 405(c)(2) and no bonus allowances. City of

Henderson's Henderson unit in Kentucky would have a lower allowance

allocation when total owned capacity, rather than total operated

capacity, is considered. EPA proposes to change the allowances for the

R P Smith unit and leave unchanged the allowances for the Henderson

unit. Comments are requested on this proposed resolution and from any

utility with a unit that may be affected by the proposed interpretation

of utility capacity.

City of Springfield argued, in its comments on the original

allowance allocations, that EPA should not use nameplate capacity for

determining utility capacity under section 405(c)(3). While section

405(c) (1) and (2) refer to a utility's ``aggregate nameplate fossil

fuel steam-electric capacity, section 405(c)(3) refers to a utility's

``total fossil fuel steam-electric generating capacity.'' Data

available from the Energy Information Administration (EIA) of the

Department of Energy includes three different ``capacity'' terms:

nameplate capacity, summer net dependable capability, and winter net

dependable capability. Nameplate capacity is the gross maximum capacity

(in MWe) that a generator is designed to deliver, whereas capability

refers to the highest number of MWe actually delivered during a given

season. City of Springfield recommended summing, for a utility, the

summer net dependable capability of each of its units in applying

section 405(c)(3).

Under EPA's original allowance allocations, City of Springfield's

Lakeside units 7 and 8 received basic allowances under section

405(c)(1) because City of Springfield operated units with a total of

463 MWe of nameplate capacity. Since the total summer net dependable

capability of these units was 443 MWe, City of Springfield's

interpretation will result in Lakeside units 7 and 8 instead receiving

unadjusted basic allowances under section 405(c)(3).

EPA now agrees that the utility-capacity language in section

405(c)(3) is ambiguous, particularly in light of the specific

references in section 405(c) (1) and (2) to nameplate capacity. The

legislative history does not directly address the use of different

utility-capacity language in these provisions of section 405. Further,

differences in statutory language are generally interpreted as

differences in meaning. Section 405(c)(3), unlike section 405(c) (1)

and (2), does not specify nameplate capacity. Under these

circumstances, EPA agrees that it is reasonable to conclude that some

other capacity measure was intended to be used. Most utilities in the

United States are summer peaking utilities and have larger summer net

dependable capability than winter net dependable capability.

Consequently, given the capacity measures in available EIA data, summer

net dependable capability is the most logical alternative to nameplate

capacity. EPA has not identified any units, other than the City of

Springfield's units in Illinois, whose allocations are affected by this

change in interpretation of section 405(c)(3).

Therefore, EPA proposes, for the purposes of section 405(c)(3)

only, to interpret utility capacity as the aggregate summer net

dependable capability. This allows City of Springfield's Lakeside unit

7 to receive 2,919 unadjusted basic allowances for 2000 through 2009

and 722 unadjusted basic allowances for 2010 and thereafter. Lakeside

unit 8 will receive 1,652 unadjusted basic allowances for 2000 through

2009 and 371 for 2010 and thereafter. These allowances will be in lieu

of the basic allowances provided to the units in the current Table 2.

Comments are requested on this approach.

EPA proposes another revision related to the application of section

405(c)(3). As noted above, eligibility for section 405(c)(3)

allocations is contingent on a unit being owned by an electric

generating company with fewer than 78,000 customers as of November 15,

1990. The current rule defines

[[Page 68357]]

``customer'' as ``a purchaser of electricity not for purposes of

transmission or resale.'' 40 CFR 72.2. EPA understands that generating

rural electrical cooperatives under the Rural Electrification Act (7

U.S.C. 901, et seq.) are required to serve distributing cooperatives,

which in turn serve the retail customers. Generating rural electrical

cooperatives therefore do not have ``customers,'' as the term is

currently defined. In order to address the unique circumstances of such

cooperatives, EPA is proposing to revise the definition of ``customer''

to provide that customers of a generating rural electrical

cooperative's distributing cooperative are considered customers of the

generating cooperative.

The effect of this change is to make Southern Illinois Power

Cooperative's Marion plant in Illinois eligible for allowances under

section 405(c)(3). For years 2000 through 2009, Marion units 1, 2, and

3 will be provided 2,376, 2,434, and 2,640 unadjusted basic allowances

respectively, rather than their current allowances for those years of

534, 547, and 593.

EPA proposes to implement, in this rulemaking, the above discussed

revisions in the unadjusted allowances for the Madison Gas, Potomac

Edison, City of Springfield, and Southern Illinois Power units in Table

2. However, EPA proposes that in this proceeding it will not insert in

the table the adjusted allowance figures (i.e., the allowance

allocations, which take account of the 8.9 million ton nationwide cap

on SO2 emissions and are referred to as the ``total annual phase

II'' allowances in Tables 2 and 3) for these units and will not revise

the allowance allocations of the other units on the tables to take

account of the allowance impact of the revised Madison Gas, Potomac

Edison, City of Springfield, and Southern Illinois Power unadjusted

allowances. Instead, all of these changes will be made in a future

rulemaking.

With few exceptions, sections 403(a) and 405(a)(3) prohibit total

annual allowance allocations in Phase II for all affected units from

exceeding 8.95 million. In this way, annual, nationwide SO2

emissions are essentially capped at 8.95 million tons. When total

unadjusted annual basic allowances calculated under section 405 exceed

the 8.95 million ceiling, each unit's basic allowances must be adjusted

(i.e., ``racheted'' down proportionately) to prevent the ceiling from

being exceeded. Because the current Tables 2 and 3 already reflect a

ratcheting down of each unit's allowances, any net increase or decrease

in the unadjusted annual basic allowances in Phase II for any affected

units probably changes the amount of ratcheting and thus probably

requires a change in the allowance allocations shown on Table 2 or 3

for every other unit. Only if the increases in unadjusted basic

allowances proposed today were essentially equal to the proposed

decreases would the allowance allocations of the other units remain

unchanged. In point of fact, the net effect of the revisions proposed

today (including the allowance revisions discussed above and the

corrections of Agency errors and addition of units to and deletion of

units from the tables discussed below) is a relatively small net

reduction in the total number of unadjusted basic allowances. This will

result in a small reduction in the level of ratcheting necessary to

implement the 8.95 million allowance ceiling. Reduced ratcheting may

result in a relatively small number of additional allowances being

allocated for Phase II to many units that are not otherwise affected by

today's proposal.

Adjusting all the allocation entries on Tables 2 and 3 is

administratively burdensome and expensive. Moreover, under section 403

of the Act, the allocations in the tables will have to be adjusted, and

the tables republished, in June 1998 in any event. Section 403(a)

required the Administrator to publish a final list of allowances

allocations by December 31, 1992, reflecting estimated allowances to be

allocated to units that apply for and receive repowering extensions in

the future under section 409. Section 403(a) also requires the

Administrator to publish a revised final list by June 1, 1998,

reflecting, inter alia, allowances allocated to units for which

repowering extensions are actually approved.

EPA believes that no one will be prejudiced in any significant way

by EPA's deferring allowance adjustments until the 1998 publication of

the final list of allowance allocations. The owners of units whose

unadjusted allowances are increased if today's proposal is finalized

can trade the allowance increase in anticipation of the actual

allocation in 1998. See 42 U.S.C. 7651b(b). As noted above, the change

in the ratchet and the difference between the amount of the unadjusted

allowances for these units and the amount allocated to them after

adjustment due to ratcheting will be relatively small. Similarly, the

amount of the ratcheting adjustment in 1998 of the allowances of other

units otherwise not affected by today's proposal will be small. The

owners of units that, under the proposal, are on Table 2 or 3 can trade

their current allocations and base trading decisions on the existing

ratchet for Phase II (about 10%).

Consistent with its authority under section 403(b) to establish

allowance system regulations, EPA proposes to revise the unadjusted

allowances for the Madison Gas, Potomac Edison, City of Springfield,

and Southern Illinois Power units in Table 2. The proposal includes a

provision stating that the unadjusted allowances in Table 2 (or Table

3, as appropriate) for these (and certain other) units are superseded

and setting forth the new number of unadjusted allowances for such

units. However, EPA proposes not to change, in this rulemaking, the

ratchet used to adjust all allowances on the tables. Rather than

recalculating the ratchet and applying it to all units in the tables,

EPA will leave in place the current allowance allocations for the

Madison Gas, Potomac Edison, City of Springfield, and Southern Illinois

Power units and the other units remaining in the tables. When EPA

develops the June 1998 revised list of allowance allocations required

under section 403, EPA will calculate a new ratchet and apply it to the

unadjusted basic allowances of all units remaining on Tables 2 and 3.

The resulting allowance allocations will then be reflected in the

units' Allowance Tracking System accounts.

2. Correction of Agency Errors

EPA developed the NADB in order to calculate Phase II allowance

allocations for all affected units. In July 1991, EPA released for

comment version 2.0 of the NADB. 56 FR 33278 (July 19, 1991). Section

402(4)(C) of the Act required the Administrator, by December 31, 1991,

to ``supplement data needed in support of [title IV] and correct any

factual errors in data from which affected Phase II units' baselines or

actual 1985 emission rates have been calculated * * * for purposes of

issuing allowances under the title.'' 42 U.S.C. 7651a(4)(C). EPA stated

in the July 1991 notice that it would not accept comments on the data

base after September 3, 1991 (the close of the comment period) except

if the data sought was not available by that date. EPA added that it

would not change any data after December 31, 1991, when it expected to

issue the final data base. 56 FR 33279 and 33283.

In July 1992, EPA released version 2.1 of the NADB, believing that

version to be the final, and proposed Phase I and Phase II allowance

allocations. 57 FR 30034. After correcting errors made by the Agency in

version 2.1, EPA released version 2.11 of the NADB in March 1993, along

with the final Phase II allowance allocations. 58 FR 15720 (NADB); and

58 FR 15634 (allocations).

[[Page 68358]]

The corrections to the NADB were made ``only in response to comments,

verified by EPA, that either changes were made to the data which, based

on the data in the possession of EPA at the time, were known to be

incorrect or the Agency failed to make a correction requested by a

commenter that was true and properly documented at the time.'' 58 FR

15720. At that time, EPA believed it had corrected all of these errors.

However, several utilities subsequently informed EPA that the NADB

still contained errors that were of the type that EPA had intended to

correct. In the following cases, EPA agrees that the error in the

current NADB results from the Agency's own actions. This is because the

NADB data issues had been identified to EPA by a commenter by December

31, 1991 and the commenter submitted to EPA, before EPA's issuance of

NADB version 2.1 on July 7, 1992, sufficient documentation to support

the correction of the data. Because in the March 1993 notices EPA had

intended to correct such problems, EPA proposes today to correct them

by revising the units' unadjusted allowances to reflect the correct

data. Consistent with the approach taken in the March 1993 notices, EPA

will not address any errors that were not identified by December 31,

1991 or not sufficiently documented by July 7, 1992 and will not

consider new requests for data changes, new data submissions, or new

requests for outage adjustments.23

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\23\ As discussed below in sections IV(B) and (C) of this

preamble, there are two exceptions to this approach toward data

errors. First, where data errors result in unaffected facilities

being improperly categorized as affected units, EPA proposes to

adopt the proper categorization of the units regardless of when the

data errors are corrected. Second, where projections, rather than

actual data, are involved (i.e., projected dates for commencement of

commercial operation), EPA will correct the projected dates if EPA

is made aware of the actual dates within a reasonable time after

commercial operation is commenced and all other necessary data had

been provided by December 31, 1991.

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a. In the case of Manitowoc unit 8 in Wisconsin, the shared heat

input at 60 percent capacity (HT60SHR) is not accurate. While EPA

developed a methodology for sharing heat input at 60 percent capacity

(HEAT60) that was accurate for most situations, the methodology was

inaccurate for Manitowoc's unique circumstances, i.e., where only one

boiler in a multiheader configuration was on-line as of December 31,

1987. The owner of Manitowoc timely commented on the inaccuracy on

August 30, 1991. However, EPA failed in March 1993 to correct the

methodology in a way that would account for Manitowoc's situation. EPA

has reviewed the methodology for splitting HEAT60 and developed a

method that is appropriate for multi-header configurations where one or

more, but not all, units came on-line after the baseline period. EPA is

proposing to use the proportional share of design heat input. For

example, if boiler 1 had a 100 mmBtu/hr design heat input, boiler 2 had

200 mmBtu/hr and boiler 3 had 300 mmBtu/hr, boiler 1 would be allotted

\1/6\ of the generator's HEAT60, boiler 2 would be allotted \1/3\, and

boiler 3 would be allotted \1/2\. For Manitowoc unit 8, this approach

will result in 271 unadjusted basic allowances, as opposed to 27 listed

in the current Table 2.

b. In the case of the Reedy Creek Improvement District's (Reedy

Creek) Combined Cycle 1, unit 32432 (formerly unit 11*STG) in Florida,

EPA erroneously failed to include the unit in Table 2, believing the

unit was a simple combustion turbine and so was not an affected unit.

Reedy Creek's timely comments, submitted on August 30, 1991, provided

sufficient information to properly characterize the unit as a combined

cycle turbine with auxiliary firing and thus as an affected unit and to

determine its allowance allocation. EPA proposes to include the unit in

Table 2 with 69 unadjusted basic allowances under section 405(g)(1).

c. In the case of Central Louisiana Electric Company's (Central

Louisiana) Rodemacher unit 2, EPA failed to correctly characterize the

outage request for the unit. Central Louisiana submitted the outage

request for the unit on March 21, 1991 and supplemented the request

with additional information on February 10, 1992. On July 7, 1992, as

part of the notice of the NADB (57 FR 30034), EPA proposed a

classification scheme for outage requests received by EPA prior to

finalization of the NADB. EPA proposed, at that time, and later

finalized allowing baseline adjustments for discontinuous but related

outages totalling four months or greater (``Category II''). See 58 FR

15724. However, EPA mischaracterized Rodemacher unit 2's outage as less

than four months. EPA now recognizes that Central Louisiana's earlier

submissions provided timely notice and sufficient documentation of a

discontinuous outage at Rodemacher of over four months. Unfortunately,

the February 10, 1992 supplemental submission documenting the requested

outage was received by EPA but was not directed to the docket or the

Acid Rain Division to be considered with other outage requests. The

outage at Rodemacher clearly fits the Category II classification and

would have been so classified in 1992 if Central Louisiana's

supplemental submission had been docketed. EPA stresses that it is not

reconsidering or changing the criteria for evaluating outage requests

but rather is correcting its mistake in applying the existing criteria.

Therefore, EPA proposes to allow 2,312 additional unadjusted basic

allowances for Rodemacher unit 2, bringing its total to 20,774.

d. For the reasons discussed above in section IV(A)(1) of this

preamble, EPA is proposing today changes to the unadjusted allowances

for the Manitiwoc and Rodemacher units and adding the Combined Cycle 1

unit and its unadjusted allowances to Table 2, as addressed in this

section, but is not proposing to change or add the resulting allowance

allocations in this rulemaking. The units' allowance allocations

reflecting the new figures for unadjusted allowances will be put in

Table 2 when the revised Tables 2 and 3 are issued in June 1998. At

that time, any resulting revisions of the allowance allocations for the

other units on the tables will also be made.

B. Deletion of Units From Table 2

EPA proposes to delete certain units from Table 2 of Sec. 73.10(b),

which set forth the Phase II allowance allocations for existing units.

Because of data errors, these units were erroneously treated as

affected units and included in the table. As discussed above, EPA

generally will consider correcting NADB data errors and, as a result,

changing an affected unit's allowances only where a data problem was

identified to EPA by a commenter by December 31, 1991 and was

sufficiently documented by July 7, 1992. Because the March 1993 notices

were intended to correct such errors, EPA now considers the errors to

be Agency errors and, as noted above, proposes to correct them. Other

NADB data errors relating to allocations of affected units will not be

corrected. However, EPA is taking a different approach to data errors

(whether or not the data is in the NADB) that result in units being

improperly categorized as affected units when they actually are

unaffected units.

In the latter cases, EPA will delete the units from Table 2 (or

Table 3, as appropriate) regardless of whether the data errors result

from the Agency's own actions. Any allowances allocated to such units

must be offset by return of the same number of allowances with the same

or an earlier compliance use date as those allocated. Further, the

proceeds from EPA's auctioning of any allowances allocated to such

units must be returned to EPA. Data errors, regardless of their cause,

cannot expand

[[Page 68359]]

the applicability of the Acid Rain Program as set forth in title IV of

the Act.24 The deletion of units from Table 2 is discussed below.

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\24\ While the July 1991 notice established a December 31, 1991

cut-off for changing NADB data, the notice did not suggest that

units that are unaffected units and ineligible for any allowances

would continue to be allocated allowances. EPA explained that

``[u]nits eligible for allowances will be allocated allowances based

on the data contained in the final database.'' 56 FR 33283.

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1. Following publication of the March 1993 notices, EPA was

notified by owners or operators of Grand Avenue, Kettle Falls, Maddox,

Mobile, R S Nelson, and South Meadow that these units are not affected

units under Sec. 72.6 (the applicability provisions of the Acid Rain

Program) and so should not have been listed in Table 2. All of the

units were allocated allowances.

EPA agrees that Grand Avenue units 7 and 9 in Missouri are

cogeneration facilities excluded from the Acid Rain Program under

section 402(17)(C) of the Act and Sec. 72.6(b)(4)(i). The Grand Avenue

units commenced operation prior to 1990. The NADB does not include data

on the operations of cogeneration units. The units were designed and

operated to produce municipal steam heat and electricity and are still

operated in that manner. They each supplied less than 219,000 MWe-hr

per year in 1985-1987 and in every year since 1990. EPA proposes to

remove the units from Table 2.

EPA agrees that Kettle Falls in Washington also should be deleted

from Table 2 and excluded from the Acid Rain Program as a solid waste

incinerator under Sec. 72.6(b)(7). This unit commenced commercial

operation in 1983 burning ``hog'' fuel (waste from the logging and

lumber industry). The NADB erroneously labeled Kettle Falls as an oil

and gas-fired unit. In 1991 during development of the NADB, EPA had

data demonstrating Kettle Falls' use of non-fossil fuel and

qualification under Sec. 72.6(b)(7). EPA proposes to delete the unit

from Table 2.

Maddox unit **3 in New Mexico is a simple combustion turbine (as

defined in Sec. 72.2) that originally commenced commercial operation in

1963. The turbine was moved from one site in New Mexico, where it was

called ``Roswell,'' to its present site in 1989. Section 402(8) of the

Act and Sec. 72.6(b)(1) exclude from the Acid Rain Program simple

combustion turbines that commenced commercial operation prior to

November 15, 1990. Because Maddox **3 meets these criteria, EPA agrees

that it should be removed from Table 2.

EPA agrees that Mobile unit **2 in South Dakota is not an affected

unit under the Acid Rain Program. Only units at stationary sources are

affected units. 60 FR 17100, 17108 (April 4, 1995). Mobile **2 is a

mobile source, not a stationary source, and thus, should not be

included on Table 2 as an affected unit in the Acid Rain Program.

The operator of R S Nelson units 1 and 2 in Lousiana requested on

July 17, 1992 that the units be removed from Table 2 because they are a

qualifying facility excluded from the Acid Rain Program under

Sec. 72.6(b)(5). EPA failed to act on the request before finalization

of the allocations in March 1993 but now agrees with the request. The

units are a ``qualifying facility'' (Federal Energy Regulatory

Commission Docket No. QF86-512) and are subject to a qualifying power

purchase commitment, as defined in Sec. 72.2. The installed capacity of

the units is 227.2 MWe (measured in gross), which does not exceed 130%

of the planned net output capacity of 201 MWe (measured in net). EPA

proposes to remove the units from Table 2.

EPA agrees that South Meadow units 11, 12, and 13 (now called

``Mid-CT RRF'') in Connecticut should be deleted from Table 2 because

they are solid waste incinerators excluded from the Acid Rain Program

under Sec. 72.6(b)(7). The NADB erroneously failed to reflect that,

while these units were originally coal-fired utility units, they were

shut down in 1969 and were substantially modified and resumed operation

as solid waste incinerators in 1988. EPA proposes to delete them from

Table 2.

2. EPA believes the following additional units, presently listed in

Table 2, are not affected units under Sec. 72.6:

------------------------------------------------------------------------

State Plant Units ORIS

------------------------------------------------------------------------

CO........................... Valmont......... 11,12,13,22,23.. 0477

KS........................... Ripley.......... **2,**3......... 1244

MI........................... Delray.......... 11.............. 1728

MS........................... Wright.......... W4.............. 2063

NY........................... Rochester 3..... 1,2,4........... 2640

PA........................... Richmond........ 63,64........... 3168

PA........................... Southwark....... 11,12,21,22..... 3170

TX........................... Concho.......... 2,4,5,6......... 3518

TX........................... Deepwater....... DWP1-DWP6....... 3461

------------------------------------------------------------------------

The units were not in operation during the baseline period (1985-

1987) and were designated by the Energy Information Administration

(EIA) of the U.S. Department of Energy as having retired before

November 15, 1990. In the preamble of the March 1993 notice of final

allowance allocations (58 FR 15636), EPA discussed the treatment of

retired units. At that time, EPA attempted to identify all units that

were not in operation during the baseline period and that had retired

prior to November 15, 1990; such units were considered to be unaffected

units and were deleted from Table 2. Because the units listed above

also meet these criteria, EPA proposes to delete them from Table 2.

Most of these units were not allocated allowances.

EPA requests notification during the comment period by the owners

or operators of any other unit listed on Table 2 that was not in

operation during 1985-1987 and that is designated by EIA as having

retired before November 15, 1990. If the unit will not be returned to

service, EPA may delete such units from Table 2.

3. EPA believes that several other facilities listed in Table 2 are

unaffected units because they are not fossil fuel-fired combustion

devices. El Centro 2 in California, Lauderdale PFL4 and PFL5 in

Florida, and Chesterfield **8B in Virginia are heat recovery boilers

that use exhaust gases from combustion turbines to produce steam in the

boilers and do not use any fossil fuel, e.g., through auxiliary firing.

NA 2--7246 **1 in Arkansas is planned to be a hydroelectric generation

facility and thus will not use any fossil fuel. These facilities were

allocated allowances in Table 2. EPA proposes to remove these

facilities from Table 2.

4. EPA reviewed the status of all units listed in Table 2 using the

Department of Energy's ``Inventory of Power Plants 1993'' (published in

December 1994)

[[Page 68360]]

and ``Inventory of Power Plants 1994'' (published in October 1995).

Based on that review, EPA proposes to delete units from Table 2 that

have been canceled or postponed indefinitely and therefore are not

affected units at this time. None of these units were allocated

allowances in Table 2. EPA requests comment from the owners or

operators of the following units concerning deletion of the units from

Table 2:

------------------------------------------------------------------------

State Plant Unit ORIS

------------------------------------------------------------------------

AL........................... Future Fossil... **1............. 7064

McIntosh CAES... **2............. 7063

McWilliams...... **CT1 **CT2 0553

**CT3.

IL........................... Lakeside........ GT2............. 0964

IN........................... Na1--7221....... **2............. 7221

Na1--7228....... **4,**5......... 7228

KY........................... J K Smith....... 1............... 0054

MN........................... Future Base..... **1............. 7240

MO........................... Combustion **NA7........... 7160

Turbine 1 (``CT

Plant 1'').

MO........................... Empire Energy **4 **NA2 **NA3. 6223

Ctr.

NE........................... NA1--7019....... **NA2........... 7019

NJ........................... Butler.......... **4............. 7152

NJ........................... NA5--7217....... **2............. 7217

NA6--7218....... **2............. 7218

NM........................... Escalante....... **2............. 0087

ND........................... Dakotas......... **1............. 7081

OK........................... Inola........... **1............. 0798

GT98............ **1, **2........ 7243

GT99............ **1-**3......... 7225

NA1-7216........ **1, **2........ 7216

San Miguel...... **2............. 6183

TNP One......... **3, **4........ 7030

WI........................... Manitowoc....... 9............... 4125

Na-7222......... **1............. 7222

------------------------------------------------------------------------

EPA also requests comment from owners or operators of other units

in Table 2 that will not be built or that actually are not affected

units under Sec. 72.6. EPA notes that if the owners and operators of

any unit listed in Table 2 believe that their unit is not an affected

unit, a certifying official for owners or operators of the unit may

submit a petition under Sec. 72.6(c) to have the Administrator

determine if the Acid Rain Program rules apply to the unit.25

Units that are not affected units or will not be built may be deleted

from Table 2.

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\25\ The applicability of the Acid Rain Program is described in

the guidance document, ``Do the Acid Rain SO2 Regulations Apply

to You?'', which is available from the Acid Rain Hotline at (202)

233-9620.

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5. EPA proposes to implement, in today's rulemaking, the above-

discussed deletions from Table 2 and the other deletions from or

additions to Tables 2 and 3 addressed in this proposal. H

This text is long and has been trimmed here. Open the source document for the complete record.