STATE OF TEXAS

OFFICE OF THE GOVERNOR

GEORGE W. BUSH

GOVERNOR

January 3, 2000

Mr. Gregg Cooke

Region VI Administrator

U.S. Environmental Protection Agency

1445 Ross Avenue

Dallas, TX 75202-2733

Dear Mr. Cooke:

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Enclosed are proposed revisions to Texas' State Implementation Plan (SIP) that the Texas

Natural Resource Conservation Commission (Commission) adopted on December 16, 1999.

The first package of adopted amendments to Chapters 101 and 116 implement the requirements

ofSenate Bill 7, 76th Legislature, 1999, concerning the emissions banking and trading of

allowances and the permitting of grandfathered electric generating facilities. The second

package of adopted amendments to Chapter 116 implements the new procedures for standard

permits authorized by Senate Bill 766, 76th Legislature, 1999.

The public hearing certification, complete record ofthe public hearing, and accompanying order

are also enclosed. I look forward to your expeditious approval ofthese revisions to the Texas

SIP.

W.BUSH

GWB/bb:pf

Enclosures

cc: Mr. Robert J. Huston, Chainnan, Texas Natural Resource Conservation Commission

Mr. Jeffrey A. Saitas, P.E., Executive Director, Texas Natural Resource Conservation Commission

POST OFFICE Box 12428 AUSTIN, TEXAS 78711 (512) 463-2000 (VOICE)/(512) 475-3165 (TDD)
Texas Natural Resource

Conservation Commission

Public Hearings

October 1999

Concerning Revisions To

Chapters 101 and 116

Electric Industry Restructuring (SB 7)

Rule Log Number 99033-1l6-AI

Volume lof2

"
INTRODUCTION

The commission held public hearings in EI Paso and Lubbock on October 1, 1999, in Austin on October

4, 1999, in Irving on October 5, 1999, in Houston on October 7, 1999, and in Beaumont on October 7,

1999. The hearings were held to consider amendments to Chapters 101 and 116, which implement the

requirements of Senate Bill 7, concerning the permitting of grandfathered and electing electric generating

facilities.

Written comments were accepted through October 11, 1999. All testimony and comments have been

reviewed and seriously considered. This volume contains a complete record of the public hearing and is

divided into the following four sections:

o Public Notification and Proposal

o Written and Oral Testimony

o Evaluation of Testimony

o Staff Recommendations

Additional copies of this hearing record are maintained in the TNRCC central office at 12100 North

IH-35, Austin, Texas 78753. For further information, contact Beecher Cameron at (512) 239-1495.
requirements of the Insurance Code, Article 3.42. Such forms must be

filed in accordance with and accompanied by the required certification

as prescribed in Subchapter A of this chapter (relating to Filing

of Policy Forms, Riders, Amendments and Endorsements for Life,

Accident and Health Insurance and Annuities). The certification form

required to be used in filing the certification is "TEXAS POLICY

FORM CERTIFICATIONS, Multi-Use Form," which also is to be

utilized for filing certifications for file-and-use under Article 3.42(c),

as well as for corrections, resubmissions, substitutions, and filings

for forms exempted from review and official action by these sections.

Form "TEXAS POLICY FORM CERTIFICATIONS" is available

from the Life/Health Group, has been filed with the Texas Register

Division of the Secretary of State for public inspection, and is adopted

by reference in these sections. The form also is reproduced in full as

Figure 1 in §3.4020 of this title (Relating to Appendix).

(h) Copies of Previously Approved Forms Subsequently

Submitted in Foreign Language (Non-English). Any form not

otherwise exempted under these sections that is submitted in Braille

as an exact copy of a previously approved form, or any form that has

been translated into a foreign language from its previously approved

English version, is exempt from the review and approval requirements

of the Insurance Code Article 3.42. Such forms must be filed in

accordance with and accompanied by the required certification as

prescribed in Subchapter A of this chapter. The certification form

required to be used in filing the certification is the same as that

described in subsection (g) of this section.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 20,

1999.

TRD-9908892

Lynda Nesenholtz

General Counsel and Chief Clerk

Texas Department of Insurance

Effective date: January 9, 2000

Proposal publication date: October 15, 1999

For further information, please call: (512) 463-6327

♦♦♦

Chapter 7. CORPORATE AND FINANCIAL

REGULATION

Subchapter J. EXAMINATION EXPENSES

AND ASSESSMENTS

28 TAC §7.1012

The commissioner of insurance adopts an amendment to

§7.1012 concerning assessments to cover the expenses of

examining insurance companies. The amendment is adopted

without changes to the text as proposed in the November 12,

1999, issue of the Texas Register (24 TexReg 9944).

The amendment is necessary to provide a rate of assessment

for domestic and foreign insurance company examination expenses in 2000 which will provide the revenue necessary to

fund the appropriations made by the Legislature.

Section 7.1012 provides the method and rates of assessment

for examination expenses of foreign and domestic insurance

companies. Rates of assessment are levied against and

collected from each domestic insurance company based on

admitted assets and gross premium receipts for the 1999

calendar year, and from each foreign insurance company

examined during the calendar year 2000 based on a percentage

of the gross salary paid to an examiner for each month

or part of a month during which the examination is made.

The department anticipates that the adopted rate will produce

revenue of $12,147,056 to the state’s general revenue fund.

The expenses and charges to be assessed are in addition to,

and not in lieu of, any other charge which may be made under

the law, including the Insurance Code, Article 1.16.

No comments were received regarding adoption of the amendment.

The amendment is adopted under the Insurance Code, Article

1.16 and §36.001 (formerly Article 1.03A). The Insurance

Code, Article 1.16(a) and (b) authorizes the commissioner

of insurance to make assessments necessary to cover the

expenses of examining insurance companies and to comply

with the provisions of the Insurance Code, Articles 1.16, 1.17,

and 1.18, in such amounts as the commissioner certifies to

be just and reasonable. In addition, Article 1.16(c) provides

that expenses incurred in the examination of foreign insurers

by Texas examiners shall be collected by the commissioner by

assessment. Section 36.001 (formerly Article 1.03A) authorizes

the commissioner of insurance to adopt rules and regulations

for the conduct and execution of the duties and functions of the

department only as authorized by statute.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 20,

1999.

TRD-9908907

Lynda Nesenholtz

General Counsel and Chief Clerk

Texas Department of Insurance

Effective date: January 9, 2000

Proposal publication date: November 12, 1999

For further information, please call: (512) 463-6327

♦♦♦

TITLE 30. ENVIRONMENTAL QUALITY

Part 1. TEXAS NATURAL RESOURCE

CONSERVATION COMMISSION

Chapter 101. GENERAL AIR QUALITY RULES

Subchapter H. EMISSIONS BANKING AND

TRADING

Division 2. EMISSIONS BANKING AND

TRADING OF ALLOWANCES

30 TAC §§101.330-101.337

The Texas Natural Resource Conservation Commission

(TNRCC or commission) adopts new §101.330, Definitions; §101.331, Applicability; §101.332, General Provisions;

§101.333, Allocation of Allowances; §101.334, Allowance

25 TexReg 128 January 7, 2000 Texas Register
Deductions; §101.335, Allowance Banking and Trading;

§101.336, Emission Monitoring, Compliance Demonstration,

and Reporting; and §101.337, El Paso Region. The sections

are adopted with changes to the proposed text as published

in the September 10, 1999 issue of the Texas Register (24

TexReg 7137). The adopted rules will also be submitted as a

proposed revision to the state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS

FOR THE ADOPTED RULES

Senate Bill 7 (SB 7), 76th Legislature, 1999, amended the

Texas Utilities Code (TUC), Title 2, Public Utility Regulatory

Act, Subtitle B, Electric Utilities, and created a new Chapter

39, Restructuring of Electric Utility Industry. SB 7 requires

the commission to implement the permitting and allowance

requirements of new TUC, §39.264, concerning Emissions

Reductions of "Grandfathered Facilities." TUC, §39.264 requires

the commission to develop a mass cap and trade system

to distribute emission allowances for use by grandfathered

and electing electric generating facilities (EGF). Under TUC,

§39.264, two categories of EGFs are eligible to use the

adopted trading system. The first category consists of EGFs

in existence on January 1, 1999, which were not subject to

the requirement to obtain a permit under Texas Clean Air

Act (TCAA), §382.0518(g). These facilities are referred to

as "grandfathered" facilities. The second category of EGFs

consists of permitted EGFs that are not subject to the permitting

requirements of TUC, §39.264, yet elect to participate in the

allowance trading system. These facilities are referred to as

"electing" EGFs. TUC, §39.264 also requires that grandfathered

EGFs apply for a permit on or before September 1, 2000, and

obtain a permit by or cease operation after May 1, 2003.

These new sections are adopted concurrently with new sections

in 30 TAC Chapter 116, concerning Control of Air Pollution

by Permits for New Construction or Modification. The new

Chapter 116, Subchapter I, concerning Electric Generating

Facility Permits, contains the requirements for permitting of

grandfathered and electing EGFs. The adopted amendments to

Chapter 116 are published in this issue of the Texas Register.

TUC, §39.264(g) and (h) requires the commission to allocate

emission allowances to grandfathered EGFs in defined regions

of the state. As stated in TUC, §39.264(c), the Legislature intended that total annual emissions of nitrogen oxides (NOx

) from

grandfathered EGFs would not exceed 50% of the emissions

during 1997 as reported to the commission, and additionally for

coal-fired grandfathered EGFs, total annual emissions of sulfur dioxide (SO2

) would not exceed 75% of the emissions during 1997 as reported to the commission. To further this goal,

TUC, §39.264(h) provided emission rates to calculate specific

allowances.

TUC, §39.264(c) allows emission limitations to be met through

an emissions allocation and allowance transfer system. An

allowance trading program is a regulatory program which caps

emissions over a designated region to a level consistent with

regulatory goals. Each grandfathered and electing EGF must

hold allowances equal to or greater than its emissions to be in

compliance with the program. For example, if a grandfathered

EGF’s emissions are 100 tons over the control period, the

compliance account for this grandfathered EGF should reflect

a balance equal to or greater than 100 tons of allowances.

The program encourages EGFs to determine the methods

of control which will allow the EGF to meet its allowances.

Further, the program allows for trading of allowances between

grandfathered and electing EGFs in the same region, thereby

creating alternatives for control. For example, if a grandfathered

EGF emitted 100 tons over the control period and has a balance

of 150 allowances in its compliance account, the grandfathered

EGF may sell the unused portion–50 tons of allowances–to

another grandfathered or electing EGF. This trading provision

allows companies to determine the most economical method of

meeting the regulation, either by purchasing surplus allowances

created by another grandfathered or electing EGF’s reductions,

or by making their own reductions.

Consistent with TUC, §39.264(i), EGFs currently permitted

under 30 TAC Chapter 116, Subchapter B, concerning New

Source Review Permits, may elect to participate in the permitting program adopted concurrently in Chapter 116, Subchapter

I. These permitted facilities electing to participate in the permitting program under Chapter 116, Subchapter I are called "electing" EGFs. In the concurrently adopted amendments to Chapter

116, the existing New Source Review (NSR) permit will be altered to include a reference to a permit issued under Chapter

116, Subchapter I. Participation in the permitting program will

allow electing EGFs to obtain allowances under the emissions

banking and trading of allowances (EBTA) program. It may be

advantageous for a company to include all EGFs, regardless

of permitting status, in the permitting program to allow maximum flexibility in control strategies. Under TUC, §39.264(i)(2)

and (4), electing EGFs are given allowances equal to their actual emissions reported in the 1997 Emissions Scorecard from

EPA’s Acid Rain Program unless a federal or state standard

otherwise limits the emission rate.

SECTION BY SECTION DESCRIPTION

The new §101.330 contains the definitions to be used in the

EBTA. "Allowance" means the authorization to emit one ton of

NOx or SO2 during the specified control period or any specified

control period thereafter. "Authorized account representative"

is the responsible person who is authorized, in writing, to transfer and otherwise manage allowances. "Banked allowance" is

an allowance which is not used to reconcile emissions in the

designated year of allocation, but which is carried forward into

next year and noted in the compliance or broker account as

"banked." In response to public comment, a new definition of

"Broker" was added to §101.330(4). "Broker" means a person who opens an account and participates in the EBTA for

the purposes of banking and trading emissions allowances and

not to satisfy emission requirements of an EGF. "Broker account" means the account where allowances held by a broker

are recorded. Allowances held in a broker account may not be

used to satisfy compliance requirements for these rules. Grandfathered and electing EGFs can purchase allowances from brokers; however, the allowances are not eligible to meet reduction requirements until the ownership of the allowances has

been transferred and the allowances reside in the purchaser’s

compliance account. The definition of "Coal" was added to

§101.330(6) to clarify any references to coal-fired EGFs. "Coal"

means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and

Materials Designation ASTM D388 92 ’’Standard Classification

of Coals by Rank’’ (as incorporated by reference in Title 40

Code of Federal Regulations (CFR), §72.13 (effective June 25,

1999)). The definition of "Coal-fired" was added to §101.330(7)

to clarify any references to coal-fired EGFs. "Coal-fired" means

the combustion of fuel consisting of coal or any coal-derived

ADOPTED RULES January 7, 2000 25 TexReg 129
fuel (except coal-derived gaseous fuels with a sulfur content

no greater than natural gas), alone or in combination with any

other fuel. The definition is independent of the percentage of

coal or coal-derived fuel consumed during any control period.

"Compliance account" means the account for a grandfathered or

electing EGF or for multiple grandfathered or electing EGFs in

which allowances are held. An EGF not under common control

or ownership may have separate compliance accounts for the

purpose of meeting the requirements of the EBTA and Chapter

116, Subchapter I. "Control period" means the 12-month period

beginning May 1 of each year and ending April 30 of the following year, which is consistent with TUC, §39.264(c). Control

periods will begin May 1, 2003. "East Texas Region" means all

counties traversed by or east of Interstate Highway 35 (IH-35)

north of San Antonio, or traversed by or east of Interstate Highway 37 (IH-37) south of San Antonio, and also including Bexar,

Bosque, Coryell, Hood, Parker, Somerville, and Wise Counties.

The commission has modified the definition of "East Texas Region" from TUC, §39.264(g) to clarify that counties east of IH-35

and west of IH-37 are not included in this region. The commission believes that had the Legislature intended for the definition

to include these counties, the definition would have simply referenced IH-35 and not IH-37 also. Additionally, these counties

(between IH-35 and IH-37) have been excluded from commission plans involving statewide air control strategies, and the

commission believes that the Legislature was attempting to be

consistent with current commission planning structures. "Electric generating facility" means a facility that generates electric

energy for compensation and is owned or operated by a person

in this state, including a municipal corporation, electric cooperative, or river authority. "Electing electric generating facility" is

an EGF that is not subject to the requirements of TUC, §39.264,

that elects to comply with Chapter 116, Subchapter I. The definition of "El Paso Region" was revised in response to comments,

and the basis for this revision is discussed in the ANALYSIS

OF TESTIMONY portion of this preamble. The "El Paso Region" is now defined to include all of El Paso County, Ciudad

Juarez, Mexico, and Sunland Park, New Mexico. The definition for "Grandfathered electric generating facility" was added

to §101.330(14) to clarify any references to "grandfathered"

EGFs. "Grandfathered electric generating facility" means a facility that is not subject to the requirements to obtain a permit

under TCAA, §382.0518(g) and that generates electric energy

for compensation and is owned or operated by a person in this

state, including a municipal corporation, electric cooperative, or

river authority. The commission originally modified this definition to exclude a facility that generates electric energy primarily

for internal use, but during 1997 sold to a utility power distribution system less than one-third of its potential electrical output

capacity. This exclusion eliminates cogeneration facilities that

were not intended to be included in this program. This portion

of the definition regarding cogeneration facilities was removed

and placed under §101.331(b), regarding Applicability. The exemption was modified to also exclude EGFs that sold less than

219,000 megawatt hours to a utility power distribution system.

This reference was added to exempt small cogenerators who

may exceed the one-third limitation. This is more consistent

with the Acid Rain Program exemption for affected units. "Heat

input" is the heat derived from the combustion of any fuel at

an EGF. Heat input does not include the heat derived from reheated combustion air, recirculated flue gas, or exhaust from

other sources. The definition of "NOx

" was revised in response

to comments. "NOx allowance" is an authorization to emit NOx

,

valid only for the purposes for meeting the requirements of this

division and Chapter 116, Subchapter I. The definition of "Permitted electric generating facility" was removed from §101.330.

The term "permitted" was unclear as used in the proposed rule

as to whether "permitting" was referencing a permit under Chapter 116, Subchapter B, Subchapter H, or Subchapter I. The rules

were changed to specifically identify the type of permit being referenced. The definition of "Person" was added to §101.330(17)

in response to comments. "Person" for the purpose of initial

issuance of permits under Chapter 116, Subchapter I, and for

the issuance of allowances under these rules, includes an individual, a partnership of two or more persons having a joint

or common interest, a mutual or cooperative association, and a

corporation, but does not include an electric cooperative. "SO2

allowance" is an authorization to emit SO2, valid only for the purposes for meeting the requirements of these rules and Chapter

116, Subchapter I. "West Texas Region" means all counties not

contained in the East Texas or El Paso Regions.

The new §101.331 establishes the applicability of banking and

trading allowances. EGFs subject to the concurrently adopted

Chapter 116, Subchapter I or electing EGFs would be required

to comply with EBTA. The section also allows the opening of

broker accounts for those not required to participate in the

EBTA. Since §101.330(4) now includes the definition of "Broker,"

this section was revised to refer to "brokers."

The new §101.332 contains the general provisions for the

EBTA. Compliance with the allowance system would begin

with the control period beginning May 1, 2003. Allowances

would only be valid for meeting the purposes of the EBTA,

and cannot be used to meet or exceed the limitations of any

permit or applicable law, generate emission reduction credits,

or satisfy emission offset requirements under federal NSR.

Because allowances do not by themselves meet federal criteria

as creditable emission reductions, they may not be used to

satisfy other requirements of the Federal Clean Air Act (FCAA),

such as netting for Prevention of Significant Deterioration

(PSD), NSR, or offsets under a nonattainment NSR permit.

Neither a NOx allowance nor an SO2 allowance constitutes

a security or property right. To meet the requirements of

TUC, §39.264(e), this section requires that on June 1 of each

year, beginning in 2004, an EGF shall hold in its compliance

account a quantity of allowances that is equal to or greater

than the total emissions of that air contaminant emitted during

the prior control period. The original proposal required that

the quantity of allowances should be in place by May 1;

however, this was in response to comments to allow a 30-day

reconciliation period. The commission requires that allowances

be allocated, transferred, or used as whole allowances. For

simplicity, the number of allowances will be rounded down

for decimals less than 0.50 and rounded up for decimals of

0.50 or greater. This section also allows only one compliance

account for use by multiple permitted EGFs located at the

same property and under common ownership or control. These

limitations on the number of compliance accounts will assist

the commission in the allocation of allowances and tracking

of allowance transfers. Section 101.332(i), which incorporated

TUC, §39.264(n), concerning the deduction of allowances from

compliance accounts where the EGF exceeded its allowances,

was moved to §101.333(4) for organizational clarity.

The new §101.333(1) and (2) contains the methods by which allowances for grandfathered and electing EGFs are calculated.

As specified in TUC, §39.264(h), the allowances will be calculated by multiplying total heat input measured in millions of

25 TexReg 130 January 7, 2000 Texas Register
British thermal units (MMBtu) during 1997 by an emission rate

expressed in pounds/MMBtu divided by 2,000. To determine

allowances, the commission will use information obtained from

the United States Environmental Protection Agency’s (EPA)

1997 Acid Rain Program’s Emissions Scorecard. This scorecard is the only readily-available, consistently-reported, and

comprehensive source of 1997 heat input data for EGFs. This

was the basis for determining the emission rates necessary to

achieve the program’s goals of a 50% reduction in NOx emissions, and for coal-fired EGFs, 25% reduction in SO2 emissions

from 1997 levels. If information for an EGF concerning heat

input is not reported to the acid rain scorecard, the executive

director may approve a method for calculating heat input for that

EGF as long the method is consistent with the requirements

of the acid rain scorecard. Paragraphs (1) and (2) also specify the emission rates for the El Paso, East Texas, and West

Texas Regions. In the East Texas Region, the emission rate

is 0.14 pounds of NOx per MMBtu and 1.38 pounds of SO2 per

MMBtu. The emission rate in the West Texas and El Paso Regions is 0.195 pounds of NOx per MMBtu. Consistent with TUC,

§39.264(i)(2), the allowances for electing EGFs are equal to the

EGF’s emission in tons in 1997. Should a coal-fired EGF permitted under Chapter 116, Subchapter B, elect to participate in

the permitting program under Chapter 116, Subchapter I, the

annual emissions of SO2 from 1997 would be used to establish

its allowances.

In addition to the 50% reduction expected from grandfathered

EGFs under TUC, §39.264, the commission anticipates adopting additional requirements for EGFs in nonattainment areas

to meet the ozone National Ambient Air Quality Standard

(NAAQS). For each nonattainment area, the amount of reductions for the SIP will be consistent with the SIP modeling efforts

for that area. At this time, the point source reductions expected

in the Dallas/Fort Worth (DFW) area are 88%. Reductions in

the Beaumont/Port Arthur (BPA) area are expected to be 40-

50%, and reductions in the Houston/Galveston (HGA) area are

expected to be 90%. The commission expects to propose the

reductions for BPA and DFW areas in December of 1999. For

the HGA area, proposal is expected in May of 2000. The commission expects to propose reductions in attainment counties

of east and central Texas not later than December of 1999.

Future rulemaking addressing these reductions may affect the

EBTA and the allocation of future allowances. TUC, §39.264(s)

recognizes the current authority of the commission to require

additional reductions of NOx or SO2

, and as future SIP rules are

developed allowances may be reduced accordingly. The new

§101.333(3) incorporates this authority. The new §101.333(4),

concerning the deduction of allowances from compliance accounts where the EGF exceeded its allowances, was added to

incorporate the requirements of TUC, §39.264(n). Paragraph

(4) was moved from §101.332(i) for organizational clarity.

The commission must allocate allowances for grandfathered

EGFs by January 1, 2000, as required by TUC, §39.264(h).

In order to meet this deadline, the commission will issue an

order prior to January 1, 2000 to allocate these allowances.

The list entitled "Nitrogen Oxide and Sulfur Dioxide Allowances

for Grandfathered Electric Generating Facilities" is available

from the commission on request and is available on the

commission’s Web Site. To meet the statutory deadline to issue

allowances by January 1, 2000, the new §101.333(5) provides

that a commission order will be issued by that date with the

allowances for grandfathered EGFs. The allowances allocated

for subsequent years will reflect the same values issued in the

initial allocation.

Initial allowances for electing EGFs for the control period

beginning May 1, 2003 will be allocated by January 1, 2001.

Since the commission will not know which EGFs are electing to

participate in the permitting program until September 1, 2000, it

would be impossible to allocate allowances for electing EGFs on

the same schedule as the grandfathered allocations. This later

allocation schedule will allow companies to determine whether

to participate in the programs and which programs best suit

their individual business needs. The new §101.333(5)(A)(ii),

formerly §101.333(4)(A)(ii), requires allocation of allowances for

electing EGFs by January 1, 2001. This section was revised to

include municipal corporations, electric cooperatives, and river

authorities that choose to obtain a permit under Chapter 116,

Subchapter I for EGFs that were previously exempted under 30

TAC §116.910(d) from the permitting program. These EGFs will

also be allocated allowances by January 1, 2001.

To allow EGFs to identify potential sellers of allowances, the

commission shall maintain a publicly available registry of the

allowances in each compliance account as provided in the

new §101.333(7). For each transfer, the registry shall include

the price paid per allowance. The registry shall not contain

proprietary information. The commission believes that public

access to information regarding the price and transfer of

allowances will promote an open trading system.

In response to comments, the new §101.334 was renamed

"Allowance Deductions" and modified extensively from the

proposal. The section now addresses only the deduction of

allowances from compliance accounts. The section specifies

the method or equations that will be used to determine the

amount of allowances to be deducted at the end of each control

period from compliance accounts in three circumstances: (1) for

electing EGFs whose heat input for the control period is equal

to or greater than its heat input for 1997, for all grandfathered

EGFs, and electing EGFs whose heat input for the control

period is less than its heat input for 1997 where the reduced

utilization or shutdown has been replaced by another EGF

permitted under Chapter 116, Subchapter I. This formula allows

any surplus allowances not used by grandfathered EGFs and

any surplus allowances not created by reduced utilization or

shutdowns from electing EGFs to be banked or traded; (2)

for electing EGFs if the heat input for the control period was

less than the heat input for 1997 and whose reduced utilization

or shutdown has not been replaced by another EGF. The

formula ensures that surplus allowances resulting from reduced

utilization or shutdowns from these electing EGFs cannot be

banked or transferred, as provided in TUC, §39.264(i)(3); and

(3) for electing EGFs whose heat input for the control period was

less than the heat input for 1997, whose reduced utilization or

shutdown has been replaced by another EGF, and for EGFs

not permitted under Chapter 116, Subchapter I. This formula

allows surplus allowances to be banked or traded if they were

generated from reduced utilization or shutdown and the EGF

can document that the reduced utilization or shutdown has been

replaced by another EGF. The requirements concerning the

trading of allowances have been moved to a new §101.335.

The new §101.335, Allowance Banking and Trading, contains

the general requirements for banking and trading of allowances.

The requirements in this section are necessary to ensure consistency with TUC, §39.264(j). The new §101.335(a) specifies

that allowances may only be used for the current or subseADOPTED RULES January 7, 2000 25 TexReg 131
quent control period for which they were allocated. Any surplus

allowances not used during a control period may be banked

for use in subsequent control periods. Allowances may only

be used within the same region. The new §101.335(b) specifies that allowances may be traded at any time during a control

period by authorized account representatives. Notification of

trades must be made to the commission within 30 days of the

trade. The new §101.335(c) specifies that trades are prohibited prior to May 1, 2003. The new §101.335(d) specifies that

traded allowances held in compliance accounts must have originated from EGFs in the same region, and the new §101.335(e)

specifies that allowances held in broker accounts may only be

transferred to compliance accounts for EGFs located in the region where the allowances were originally allocated.

Section 39.264 allows EGFs the flexibility to decide when and

where to make reductions or to add on controls. EGFs should

consider local impacts of allowance trades specifically on those

counties which are nonattainment and near-nonattainment. For

example, most near-nonattainment areas have EGFs that are

in close proximity to these areas. These EGFs emit significant

amounts of NOx

, which has been shown to heavily influence

local ozone levels. Other EGFs located a greater distance from

these areas have regional impacts on background ozone levels,

but do not impact near-nonattainment areas to the extent the

closer facilities can.

While the commission believes that the trading program will

result in emission reductions throughout the East Texas Region,

emission reductions, rather than allowance trades, at the nearby

EGFs should be thoroughly considered before investments

are made for emission control equipment at more distant

plants. In making these economic decisions, it is incumbent on

businesses to weigh the environmental consequences of their

actions. Prior to making an allowance trade to a nonattainment

or near-nonattainment area, EGFs must be aware that such

trades might jeopardize the status of a near-nonattainment area.

For example, at this time the Tyler/Longview/Marshall area is

operating under the terms of a flexible attainment region (FAR).

If numerous trades occur into that area, the conditions of the

FAR may be compromised. The FAR will expire in September

2001 and can be extended by the parties. During the term of

the FAR agreement, EPA will treat the area under an approach

similar to a maintenance plan area. However, EPA may

designate the area as nonattainment, regardless of whether a

FAR agreement is in place. Designation of nonattainment could

result in additional reductions of NOx from EGFs in the Northeast

Texas FAR area. Furthermore, a nonattainment designation

would require additional reductions from industry sources and

potential restrictions on trade into the new nonattainment area.

The commission encourages EGFs to consider the long-term

consequences of decisions to utilize allowances rather than the

installation of controls at EGFs located close to nonattainment

areas and in near-nonattainment areas.

The new §101.336 establishes compliance demonstration methods. All grandfathered and electing EGFs using the EBTA

must comply with 30 TAC §116.914, Emissions Monitoring and

Reporting Requirements. By June 30 of each year, grandfathered and electing EGFs participating in the EBTA shall report

to the commission the amount of emissions of each allocated

air contaminant during the preceding control period. The new

§101.336(b) requires that at the end of each control period, the

owner or operator of a grandfathered or electing EGF to report

its emissions to balance the emissions with the allowances in

its compliance account.

The new §101.337 will allow grandfathered or electing EGFs in

the El Paso Region to meet emission allowances using credits

from the City of Juarez, in the United States of Mexico and from

EGFs located in Sunland Park, New Mexico. The reduction

must be reviewed and approved by the executive director and

must be surplus, permanent, quantifiable, enforceable by the

commission, and not required by other rule or law. Under TUC,

§39.264(q), §101.337 would also exempt the El Paso Region

from the EBTA if either the EPA or the commission determines

that reductions of NOx will increase ambient levels of ozone.

Currently, NOx reductions are not required for facilities in the El

Paso nonattainment area because EPA has granted a waiver

under FCAA, §182(f), concerning NOx Requirements. Under

this waiver, NOx reductions are not required if the attainment

demonstration for compliance with the ozone NAAQS can be

made without a NOx control strategy. The basis for this waiver

does not satisfy TUC, §39.264(q) because it has not been

demonstrated, under the §182(f) waiver or otherwise, that NOx

reductions would increase ambient ozone in El Paso County.

The EGFs in the El Paso Region would still be required to

obtain a permit under Chapter 116, Subchapter I regardless

of the determination that NOx reductions are counterproductive

in controlling ambient ozone levels in the El Paso Region. The

commission believes that this requirement is appropriate since

TUC, §39.264(e) provides that EGFs without a permit may not

operate after May 1, 2003, and TUC, §39.264(q) refers only to

reduction requirements, not permitting requirements.

FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the adopted rulemaking in light

of the regulatory analysis requirements of Texas Government

Code, §2001.0225, and has determined that the rulemaking

is not subject to §2001.0225 because it does not meet the

definition of a "major environmental rule" as defined in that

statute. "Major environmental rule" means a rule the specific

intent of which is to protect the environment or reduce risks

to human health from environmental exposure and that may

adversely affect in a material way the economy, a sector of

the economy, productivity, competition, jobs, the environment,

or the public health and safety of the state or a sector of

the state. Because the specific intent of the adoption is

procedural in nature and specifies how and when emission

allowances can be banked and traded; makes the trading and/

or banking of emission allowances voluntary; and allows the

EGFs the flexibility to decide the extent of banking and trading

of allowances, the rulemaking does not meet the definition

of a "major environmental rule." The adopted sections only

apply to grandfathered EGFs and electing EGFs. Finally, the

adopted sections do not meet any of the four applicability

requirements of a "major environmental rule." The adopted

sections do not exceed a standard set by federal law, exceed

an express requirement of state law, or exceed a requirement of

a delegation agreement. In addition, the sections are adopted

specifically to implement the requirements of TUC, §39.264.

TAKINGS IMPACT ASSESSMENT

The commission has prepared a takings impact analysis under

Texas Government Code, 2007.043.The following is a summary

of that analysis. While these amendments may result in capital

costs for some EGFs, the amendments do not affect private

property in a manner that restricts or limits an owner’s right

25 TexReg 132 January 7, 2000 Texas Register
to the property that would otherwise exist in the absence of

the governmental action. Consequently, this adoption does not

meet the definition of a takings under Texas Government Code,

§2007.002(5). These new sections implement the requirements

of TUC, §39.264. EGFs are required to reduce emissions of NOx

by 50% and, if applicable, SO2, by 25%. Although EGFs are

required to make specific emission reductions, these facilities

have alternatives available under the banking program that may

allow the EGF to avoid installing add-on controls. Further,

allowances can be transferred under the banking program so

that EGFs have opportunities to buy and sell allowances in

order to respond to business needs. This action is intended

to reduce emissions of NOx and SO2

. The action significantly

advances this purpose by requiring substantial reductions in

the emission of NOx and SO2 through a system of emission

allowances. While requiring these reductions, these rules allow

the trading of emission allowances so that EGFs may transfer

allowances providing flexibility for compliance with emission

limits. This action is taken in response to a real and substantial

threat to public health and safety and significantly advances the

health and safety purpose and imposes no greater burden than

is necessary to achieve the health and safety purpose.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission has determined that this rulemaking relates

to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources

Code, §§33.201 et seq.), and the commission’s rules in 30

TAC Chapter 281, Subchapter B, concerning Consistency with

Texas Coastal Management Program. As required by 31 TAC

§505.11(b)(2) and 30 TAC §281.45(a)(3), relating to actions and

rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and

policies of the CMP. The commission has reviewed this action

for consistency with the CMP goals and policies in accordance

with the regulations of the Coastal Coordination Council. For

the adopted sections relating to the authorization of emission

allowances and the banking and trading of allowances, the commission has determined that the rules are consistent with the

applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural

resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas.

This adoption is intended to reduce overall emissions of NOx

and SO2 from EGFs. This action is consistent with 40 CFR because it does not authorize an emission rate in excess of that

specified by federal requirements.

PUBLIC HEARINGS AND COMMENTERS

The commission conducted public hearings concerning this

adoption in El Paso and Lubbock on October 1, 1999, in Austin

on October 4, in Irving on October 5, in Houston on October 7,

and in Beaumont on October 7.

The following commenters submitted written comments or provided testimony during the public comment period which closed

on October 11, 1999: EPA-Acid Rain Division (EPA-ARD); EPAClean Air Markets Division (EPA-CAMD); EPA-Air Permits Division (EPA-APD); EPA-Air Planning Section (EPA-APS); University of Texas System, Office of General Counsel (UT); Enron, Central and South West Services, Inc. (CSW); TXU Business Services (TXU); Brazos Electric Power Cooperative, Inc.

(Brazos); Baker & Botts, L.L.P.-Texas Industry Project (Baker

& Botts); Clark & Seay, L.L.C. (Clark & Seay); Southwestern

Public Service Company (SPS); Entergy Gulf States, Inc./Entergy Texas (Entergy); El Paso Electric Company (EPE); Lloyd,

Gosselink, Blevins, Rochelle, Baldwin & Townsend, P.C.-City

of Garland (Lloyd Gosselink); League of Women Voters of

Texas (LWV-TX); The Center for Energy and Economic Development (CEED); Association of Electric Companies of Texas,

Inc. (AECT); Reliant Energy (Reliant); Entergy Services Inc.

(Entergy Services); Environmental Defense Fund (EDF); City of

Austin/Austin Energy (AE); Sustainable Energy and Economic

Development Coalition (SEED); Public Citizen, Texas Clean Water Action, and Texas Communities Project (PC); City Public

Service of San Antonio (CPS); Sierra Club (Sierra); Bracewell

& Patterson (B&P); Lubbock Power & Light & Water (LP&L);

Clark, Thomas & Winters (CT&W); Central & South West Services, City of Austin, City Public Service, El Paso Electric, Entergy, Reliant Energy, Southwestern Public Service, and TXU

(Group A); Mothers for Clean Air (MCA); Neighbors for Neighbors (NFN); the Honorable Lon Burnam, State Representative,

District 90; and 17 individuals.

ANALYSIS OF TESTIMONY

One individual commented that the commission should exercise

its authority to require significant reductions at power plants in

East Texas, while another individual added that the reductions

should be permanent. Three individuals stated that the commission should enforce reduced emissions from grandfathered

electric generating facilities, and two more individuals added

that the commission should be as strict as possible in that enforcement.

While this adoption addresses grandfathered EGFs only, the

commission is developing rules that will apply NOx restrictions

on all EGFs in the East Texas Region. The specific level

of emissions required from these facilities will be determined

on computer analysis that indicates what reductions should be

required to assist the affected nonattainment areas in meeting

the NAAQS. The net reductions required under this adoption are

permanent. The commission will exercise its full enforcement

power as authorized by statute, rule, or as governed by

enforcement policy.

Four individuals stated that the commission should seek improvements that address SO2

, particularly to improve visibility in

Big Bend. Another individual added that the commission must

require a larger NOx and SO2 reduction to reduce acid rain and

ozone in Texas nonattainment areas.

In cooperation with EPA and the National Park Service, the commission is analyzing the nature and location of required reductions to address reduced visibility in Big Bend National Park.

This analysis is incomplete and therefore, the commission believes that requiring reductions specifically for their effect on the

Big Bend area prior to the completion of this analysis is premature. The authority granted to the commission under TUC,

§39.264 and other existing authority allows the commission to

seek additional reductions in SO2 as needed. As stated previously, the commission is addressing additional NOx reductions

that may be required to assist attainment of the NAAQS in a

separate rulemaking. There are no areas in Texas that are

nonattainment for SO2

, and the commission is not aware of any

areas that are adversely affected by acid rain.

One individual stated that the commission should not allow a

cap and trade or banking system because it avoids environADOPTED RULES January 7, 2000 25 TexReg 133
mental justice issues and perpetuates emissions in low-income

areas. The same individual suggested that the exclusion for

individual units to be regulated under TUC, §39.264 be lowered to ten megawatts from 25 megawatts. This individual also

stated that the commission estimate of cost of compliance with

the requirements of the adoption is low, and it appears that the

commission is allowing low-grade technology to be applied to

the regulated units.

The trading and banking provisions of this adoption are required

elements of the reduction program under TUC, §39.264. SB 7

provides that total annual emissions of NOx from grandfathered

EGFs will not exceed 50% of the NOx emissions in 1997 as reported to the commission and that for coal-fired grandfathered

EGFs, the total annual emissions of SO2 will not exceed 75%

of the emissions during 1997, as reported to the commission.

SB 7 also provides that the trades of allowances will only occur

within the same region, either East Texas, West Texas, or El

Paso. The effect of this will be an overall 50% reduction in NOx

and a 25% reduction in SO2 within the region. SB 7 does not

require a specific level of reduction at any individual grandfathered EGF. The exemption level for individual generating units

of 25 megawatts is specified in TUC, §39.264(d). As discussed

elsewhere in the adoption preamble, the commission has also

excluded EGFs that generate power primarily for internal use,

but that during 1997 sold one-third of their generated power

or less than 219,000 megawatt-hours to the utility power distribution system. The commission believes that excluding these

EGFs is consistent with SB 7 and will not negatively affect the

overall emission reductions required by the program. Lowering

the exemption to ten megawatts will require small generators to

participate in the EBTA and permitting program and will achieve

little environmental benefit in relation to the cost of compliance

with the program. The commission has based its estimate of the

cost of applying control technology to attain the 0.14 pounds/

MMBtu on the February 1999 joint Public Utility Commission of

Texas (PUCT) and TNRCC report, Electric Restructuring and

Air Quality: A Preliminary Analysis of Reductions and Costs of

Nitrogen Oxides Controls from Electric Utility Boilers in Texas.

The estimate does not limit the amount EGFs must spend to

meet the EBTA and accounts for technology of necessary sophistication to meet the requirements of this adoption.

The Honorable Lon Burnam, State Representative, District 90,

commented concerning the implementation of SB 7 and its

impact on consumers from an economic perspective. Mr.

Burnam expressed his concerns that the commission implement

the provisions of SB 7 free from the influence of lobbyists. Mr.

Burnam urged the commission to consider public health in the

process of implementing SB 7.

The provisions of SB 7 concerning deregulation of the electric industry will be implemented by the PUCT. The commission

conducted six hearings in order to seek the public comment of

citizens, the regulated community, and environmental groups.

The hearings were conducted in El Paso, Lubbock, Austin, Irving, Houston, and Beaumont. Prior to proposal, the commission

held a stakeholder meeting to seek input from interested persons. Notice of this meeting was provided on the commission’s

web page. In addition, pre-proposal drafts of the rules were

posted on the commissions’s web page with a request for comments. The commission believes that the adopted rules are

consistent with SB 7 and remains committed to implement the

program in a fair and impartial manner. Since EGFs are being

permitted under the requirements of TUC, §39.264, which does

not require a health effects review, no review is included in this

adoption. The commission believes that this program will reduce ambient levels of NOx and SO2 and improve the overall air

quality of the state. These reductions will assist the commission

in its efforts to attain the health-based NAAQS.

Clark & Seay and MCA commented that all power plants that

are in or near an area with unsafe air should be required to meet

the 0.14 pounds/MMBtu standard used in federal laws and to

the level to which all grandfathered plants will be required to be

cleaned up. In addition, LWV-TX commented that the rules in

general should be expanded to require that all power plants in

areas with unsafe air or that contribute to those nonattainment

areas meet the same standard.

This adoption implements the requirements of TUC, §39.264

and application of this statute is limited to grandfathered EGFs

and those EGFs that elect to participate in the permitting and

trading program. The intent of SB 7 is not to achieve attainment

with the NAAQS, but to permit and reduce emissions from

grandfathered EGFs. While the implementation of SB 7 will

provide emission reductions in areas near grandfathered EGFs,

the commission recognizes that it will likely be necessary to

adopt rules that will require air pollution control in attainment

areas as well as additional rules for nonattainment areas.

These controls would not only apply to emissions of NOx from

grandfathered EGFs, but permitted EGFs and other sources

of NOx as well. In addition, the commission will establish

emission rates that it has determined are necessary to meet air

quality standards. Rules implementing these additional controls

are scheduled for proposal in late 1999 or early 2000. The

commission is not aware of any federal standards that require

EGFs to meet a NOx emission restriction of 0.14 pounds/MMBtu.

EDF commented that TUC, §39.264(n)(1) includes two specific

penalties for facilities that exceed their allowances. The

commenters noted that the proposed rules did not include any

administrative penalties, and recommended that they be added

at a level sufficient to deter noncompliance. EDF recommended

three times the current market value of allowances.

The commission does not typically address the amount of administrative penalties in specific rules. Rather, penalty amounts

are established in accordance with the commission’s penalty

policy. All enforcement cases not referred to the Office of the

Attorney General go through staff preparation of an administrative penalty recommendation in accordance with the commission’s penalty policy. Staff obtains an agreement or litigates to

obtain an order against the respondent that requires the payment of penalties. The commission determines the amount of

the penalty in accordance with the commission’s enforcement

rules and penalty guidance. The statutory language requires

"enforcing an administrative penalty" and not "assessing" an

administrative penalty.

Reliant requested that the published list of grandfathered EGFs

should be revised by deleting the Cedar Bayou Units 1 and 2

(Account Number CI-0012-D) because the units are no longer

grandfathered and are permitted under Permit Number 1532.

In addition, Reliant provided heat input information for facilities

that were missing from the proposed list. CPS commented

that V.H.Unit 1 should be corrected from 2,946,936 MMBtu to

2,949,512 MMBtu, as was submitted to EPA in the Acid Rain

Database.

25 TexReg 134 January 7, 2000 Texas Register
The commission will make these corrections to the list entitled "Nitrogen Oxide and Sulfur Dioxide Allowances for Grandfathered Electric Generating Facilities" as requested.

EPE commented that the language in TUC, §39.102(c) and

§39.264(i) illustrate EPE’s exemption from Chapter 39 and

EPE’s ability to elect to designate a facility to become subject

to §39.264, and the commenter noted that EPE is a "person"

under TUC.

The commission agrees that EPE is a "person" under the

TUC. The commission has not revised the rule to exempt EPE

from the program requirements. TUC, Subchapter C, Retail

Competition, §39.102, concerns retail customer choice, and

exempts from TUC, Chapter 39, any electric utility that has a

system-wide freeze for residential and commercial customers

that is in effect from September 1, 1997 and extends beyond

December 31, 2001, that has been found by a regulatory

authority to be in the public interest. Subchapter C also contains

§39.264, which requires any EGF that existed on January 1,

1999, that is not subject to the requirement to obtain a permit

under TCAA, §382.0518(g), to apply for and obtain a permit

from the commission.

Section 39.264 was added to SB 7 during the final weeks

of the 76th Legislative Session. Its very specific intent is

to require grandfathered EGFs to obtain a permit from the

commission and to obtain reductions of NOx and SO2 in the

regions as defined by the bill. TUC, §39.264 contains several

specific references to the El Paso area that make it clear

that the Legislature intended EGFs in that area to be subject

to the permitting and allowance program. TUC, §39.264(g)

requires the commission to develop rules that define the "El

Paso Region." TUC, §39.264(h) specifies an emission rate for

the El Paso Region. TUC, §39.264(p) specifically requires the

commission to develop rules to allow EGFs in the El Paso

Region to meet emissions allowances by using credits from

reductions made in Ciudad Juarez, United States of Mexico.

Finally, TUC, §39.264(q) allows the commission to exempt

EGFs in the El Paso Region if the commission determines

that reductions in NOx would result in an increased amount of

ambient ozone levels in El Paso County.

The Code Construction Act, §311.021, Texas Government

Code, provides that "In enacting a statute, it is presumed that:

(1) compliance with the constitutions of this state and the United

States is intended; (2) the entire statute is intended to be effective; (3) a just and reasonable result is intended; (4) a result feasible of execution is intended; and (5) public interest is favored

over any private interest." If TUC, §39.102 were read to exclude

EGFs in the El Paso Region from the provisions of Chapter 39,

the specific provisions of TUC, §39.264, concerning the El Paso

Region, would be rendered ineffective. As prescribed by the

Code Construction Act, the commission must interpret the provisions of Chapter 39 so that all sections can be given effect.

To do otherwise would contravene the intent of the Legislature.

Thus, the commission agrees the EPE is exempt from the provisions regarding customer choice in TUC, Chapter 39. However,

if EPE were exempted from the permitting and EBTA requirements, the provisions of TUC, §39.264, concerning the El Paso

Region, would be meaningless. The commission agrees that

EPE may use the provisions of §116.912, concerning Electing

EGFs.

Lloyd Gosselink commented that the rules do not address the

use of oil as a backup fuel at a gas-fired facility. The commenter

stated that under certain curtailment situations, gas may not be

available, and gas-fired facilities may be required to switch to

oil as a fuel source, and that under these conditions, facilities

should not be penalized for any additional NOx emissions.

The commission believes that a facility has the latitude to use

any fuel as long as actual emissions comply with its allotted

allowances, and the use is authorized by the appropriate NSR

authorization. The commission does not believe it is appropriate

to revise the rules to include an exception to exceed allowances

in the case of a curtailment, because SB 7 does not allow for

this exception. If a curtailment occurs, and emissions of NOx

exceed an EGF’s allowances, the commission will rely on its

enforcement policy to determine the appropriate response. Use

of previously unused fuels may constitute a modification and

require an NSR permit. The rules have not been revised in

response to this comment.

LWV-TX commented that the TNRCC should restrict pollution

trading in ways that assure significant reductions in air pollution.

SB 7 requires the commission to allocate allowances to grandfathered EGFs in defined regions of the state. The specific intent

of SB 7 is that total annual emissions of NOx from grandfathered

EGFs will not exceed 50% of the NOx emissions in 1997 as reported to the commission and that for coal-fired grandfathered

EGFs, the total annual emissions of SO2 will not exceed 75%

of the emissions during 1997, as reported to the commission.

The adopted rules provide the requirements for both the permitting of these grandfathered EGFs and an emission banking and

trading program. Both of these programs are critical to the successful reduction of the NOx and SO2 emissions contemplated

by SB 7. The EBTA contains restrictions on trading that will

ensure that the regional emission reductions are enforceable.

The commission believes the required reporting and monitoring, along with the statutorily defined enforcement provisions,

will ensure that the program achieves the reductions intended

by TUC, §39.264, and that no modification to the rule is necessary.

CEED commented that the preamble referenced adopting additional requirements for EGFs in nonattainment areas, indicating further reductions of 88% in DFW and 90% in HGA area.

The commenter stated that the emissions inventory shows that

these point sources only represent a minor source of NOx emissions, since the majority of emissions are generated by on-road

and off-road mobile and area sources, and that the inclusion of

these statements regarding the further need to reduce emissions from EGFs continues to focus attention on sources which

will not solve nonattainment problems in these areas. CEED

also commented that the proposal preamble statements that

EGFs must consider local impacts of allowance transfers and

that "EGFs emit significant amounts of NOx

, which has been

shown to heavily influence local ozone levels" are comments

without any qualifications to specific EGFs and perpetuate the

opinion by some that all EGFs emit significant levels of emissions. CPS also disagrees with the cited statements from the

proposal preamble. CPS commented further that the mandatory

SB 7 program was designed to be flexible, and allow reductions

to be made in the most cost-effective manner, adding that the

utility plants in San Antonio, owned by CPS, do not contribute

heavily to local ozone levels, as indicated by previous modeling performed by the Alamo Area Council of Governments

(AACOG) under the direction of the TNRCC. The commenter

stated that TNRCC’s concern that SB 7 allowance trading will

jeopardize the regional strategy is unwarranted, at least for the

ADOPTED RULES January 7, 2000 25 TexReg 135
near-nonattainment area of San Antonio. CPS also supports

the removal of all references to SIP requirements from the SB

7 regulations.

The reductions mandated by SB 7 only apply to grandfathered

EGFs in the defined regions of Texas. These reductions

from grandfathered EGFs will be significant; however, it is

unlikely that the reductions will be sufficient to address the

need to further reduce emissions in both attainment and

nonattainment areas. The commission believes that to achieve

attainment with the NAAQS, it will be necessary to reduce

emissions from all sources, both stationary and mobile, in both

attainment and nonattainment areas. The reductions that will

be achieved under the adopted rules will be significant towards

reaching attainment. In addition, the commission believes

that NOx emissions from EGFs are not minor, but significantly

contribute to ground-level ozone formation. The preamble

comments regarding the potential impacts of trading on nearnonattainment areas were included to show the commission’s

recognition that emissions in near-nonattainment areas may

have a negative effect on that area’s ability to remain in

attainment. Emission inventory information indicates that NOx

emissions from EGFs are approximately 47% of the stationary

source NOx emissions in the East Texas Region.

EPA-CAMD commented that in the proposed preamble, the

cost-effectiveness numbers of $4,000 per ton of NOx removed

in the absence of emissions trading, or $2,000 per ton of

NOx removed with emissions trading, seem far too high. For

example, in the May 25, 1999 Final Rule under §126 of

the FCAA (64 FR 28300), EPA determined an average costeffectiveness of $1,468 per ton of NOx removed from electric

generating units greater than 25 megawatts with emissions

trading. Estimates for cost-effectiveness of NOx control under

the Ozone Transport Committee NOx Budget Program range

from $950-1,600 per ton. Furthermore, the commenter noted

that some gas-fired units can achieve an average NOx emission

rate of 0.14 lb/MMBtu simply using combustion controls.

The commission supports the preamble language. The listed

values were based on information developed for the joint Public

Utility Commission of Texas (PUCT) and TNRCC report published in February 1999, entitled Electric Restructuring and Air

Quality: A Preliminary Analysis of Reductions and Costs of Nitrogen Oxides Controls From Electric Utility Boilers in Texas. For

simplicity in the report, the costs of emission reductions were

analyzed on a unit-by-unit basis. Thus, the potential for "overcompliance" for certain generating units in cases where it may

be more cost-effective was not captured in the analysis. A subcommittee of the Ozone Transport Assessment Group (OTAG)

has analyzed market-based emission trading options, such as

the EBTA, estimating potential savings of as much as 50%,

compared to the costs of unit-by-unit compliance. This analysis is applied to all utility generating units in the state, which

may overstate the magnitude of the estimated compliance costs.

The commission believes that, in practice, the costs of permitting and participation in the EBTA will be much less that what

was estimated in the proposal.

EPA-APD commented on its understanding that the TNRCC

will use the emission reductions which occur under these

regulations to help demonstrate attainment and maintenance of

NAAQS. The commenter further understood that the reductions

will not be used for offsets and netting under NSR. With

this understanding, EPA-APD supported the adoption of these

regulations if the TNRCC adequately addresses the remaining

comments.

The EBTA and electric generating facility permit (EGFP) programs will be submitted as a revision to the SIP. The resulting

reductions will be used by the commission to further its attainment goals. Allowances cannot be used to satisfy emission

offset requirements under federal NSR; thus, they will not be

used as netting for PSD or for offsets under a nonattainment

NSR permit.

PC recommended substituting renewable energy for electricity

or energy used at a grandfathered facility, stating that this

could provide a low-cost way to reduce emissions and result

in the building of additional new clean energy sources. The

commenter stated that concurrent rulemaking at the PUCT

to implement the renewable portfolio standard in SB 7 has

resulted in the development of capacity factors and other

evaluation procedures that can be useful to the commission

in converting renewable capacity to energy for purposes of

calculating avoided emissions and providing for a periodic

update for that factor. PC stated that these rules developed

by the PUCT should be incorporated by reference into the

commission’s rules.

The purpose of this rulemaking is to obtain emissions reductions

from EGFs based on the specific provisions of SB 7; in

particular, the 50% NOx reductions and the 25% SO2 reductions,

if applicable. These reductions are to be made based on certain

emission rates set forth in TUC, §39.264(h). It is possible that a

grandfathered or electing EGF could make reductions relying on

the use of renewable energy and that the factors developed by

the PUCT may be used to evaluate such a proposal. Since the

commission can consider the rules of the PUCT among many

sources of information to make such decisions, the commission

does not believe it is necessary to incorporate the PUCT rules

into Chapter 101 or Chapter 116. The commission agrees that

using renewable energy to achieve emission reductions is a

viable option and one that might result in cost savings to certain

facilities. As the commission continues to develop the permitting

and EBTA programs, issues concerning renewable energy can

be considered. In addition, if a grandfathered or electing EGF

substitutes renewable energy, the resulting emissions should be

lower, requiring fewer allowances for compliance, thus creating

an economic incentive.

PC believes that the proposed rules will fail to assure that

emissions are actually reduced. PC believes that the utilities are

unlikely to offer a reduction at any plant other than those that are

oldest and used the least. Many of these plants are permitted

as base-load plants which operate 60-80% of the time, but are

kept only for peak use and are used infrequently, less than 20%

of the year. Thus, a facility might be glad to modify its permit

by reducing permitted emission that they would never really

produce. PC recommends that the rules should be modified to

require permit reductions based on the last five years of actual

emissions.

The commission believes that the specified emission rates

in the statute and the corresponding rules will achieve the

target reductions. The intent of SB 7 is to achieve overall

reductions of 50% NOx emissions and 25% SO2 emissions. An

electing EGF would receive allowances equal to actual 1997

emissions, not permit allowable emissions, and would only be

able to generate surplus allowances by reducing emissions

below actual 1997 levels. Also, an electing EGF may not

25 TexReg 136 January 7, 2000 Texas Register
transfer or bank allowances that are conserved as a result of

reduced utilization or shutdown unless the reduced utilization or

shutdown results from the replacement of thermal energy from

the electing EGF with thermal energy generated by any other

EGF. Further, since SB 7 provides that 1997 is the base year

for determining reductions, the commission does not believe it

has the authority to require permit reductions based on the last

five years of actual emissions. Therefore, the commission has

not changed the rules in response to this comment.

PC commented that the rules adopted for the implementation

of SB 7 should be structured in such a way as to allow the

purchase and retirement of NOx allowables issued under the

SB 7 program to be used as project emission reduction credits

under SB 766. PC recommended two alternatives. First,

the TNRCC could allow a retail electric provider (REP) to sell

renewables to the owner of a grandfathered facility and assume

that there will be a reduction in emissions per megawatt hour

(MW) at the average rate of emissions per MW for the power

plants in the area. The commenter stated that this is the least

costly way to assure that the program will work, and since

Texas is effectively an isolated electrical grid, will assure that

emissions are reduced in the state. The EPA has recognized

the Ozone Transport Assessment Group debates that addon units that produce solar electricity or solar water heaters

mitigate emissions. PC argued that a wind turbine, a solar water

heater, or gases from landfills can similarly be rated based on

capacity, converted into energy, and emissions reductions could

thus be calculated. Secondly, TNRCC could allow the REP

to buy and retire NOx credits from the SB 7 trading program

established in Chapter 101. This will assure that the emissions

are actually reduced in the 60-county east Texas airshed, but

it would add to the cost. The commenter further stated that

since the transaction is on the open market, it may be far

less costly than permit emission reductions purchased from

the competitor; and the commission can significantly reduce

the cost of the renewable energy used in the program by

declaring that the renewable plants built to meet a contracted

load under this program are pollution control devices as defined

in Chapter 383 of the Health and Safety Code. If renewable

energy installations are certified under Health and Safety Code,

§383.004, the certification will exempt the owners from property

taxes and allow them to qualify for pollution abatement bonds

issued by local governmental units as provided by Health and

Safety Code, §383.021. The combination of these two financial

benefits could erase the premium price of renewable energy

and make it the most cost-effective way to reduce emissions.

The commission will explore whether it has the authority to

declare a renewable energy source, such as wind power, to

be a pollution control device for the purposes of property tax

exemptions and pollution abatement bonds. As the EBTA and

permitting programs continue to develop, the commission can

consider issues such as the use of add-on units that produce

solar electricity or solar water heaters to reduce emissions.

The commission agrees that REPs can buy and retire SB 7

allowances under Chapter 101 and that this transaction might

be approved for use as a project emission reduction credit under

the voluntary emission reduction permitting (VERP) program

established by SB 766 as long as those allowances are not

used to meet the requirements of SB 7.

One individual commented that electric utilities should be

required to offer incentives to customers to replace inefficient

appliances and light fixtures with cost-effective and energy

saving equipment. The individual further commented that

utilities should issue rebates to individuals and businesses that

install renewable energy generating systems, and that utilities

should be required to participate in any distributed generating

project, public or private, that meets PUCT guidelines. Utilities

should be required to pay a fair price for non-polluting power

that they purchase from independent power producers. The

commenter made several suggestions for how to increase

competition among utilities, such as breaking up the distribution

grid and making accessible to any qualified electric producer

and having a large array of cogeneration industrial sites. The

commenter urged the use of nonpolluting renewable electric

energy.

These comments are beyond the scope of this rulemaking.

Therefore, the commission has not made any changes in

response to these comments.

One individual commented that gases from power companies

could be used by oil companies to assist in the production of oil,

and that these gases might not have to be reduced, they could

be pumped into the ground. The commenter also noted that

Russia has large gas fields and that gas could be used instead

of coal.

These comments are beyond the scope of this rulemaking.

Therefore, the commission has not made any changes in

response to these comments.

One individual made several suggestions for how emissions

could be reduced from utilities: school could be delayed to start

after Labor Day when it is cooler; retail establishments could be

closed on Sunday and Monday; the age for persons to obtain

drivers license could be raised to take some cars off the road or

persons without car insurance should be prohibited from driving;

people should be required to buy insurance for six or 12-month

periods; car inspection stations should be inspected to protect

against fraud; busing of school children could be eliminated or

the Dallas Area Rapid Transit buses should be used; teachers

should be assigned to schools closest to their homes; the

highways could be restructured to eliminate bottlenecks from

four lanes when they merge into two or three lanes; cars from

Mexico should be required to have a Texas inspection and

insurance; limitations could be put on the use of fireplaces;

IH-35 should be moved to the west and all trucks should

be required to use IH-35 and the same for I-20; auto racing

and drag racing strips should not allow the burning of fuels

and car manufacturers should be required to have overdrive

transmissions that activate at 55 miles per hour; Texas needs

to withdraw its bid for the Olympics to cut down on traffic and

flights; and the federal government should increase highway

funding to cut down on traffic congestion.

The comments raise issues that are beyond the scope of this

rulemaking. Therefore, the commission has not made any

changes in response to these comments.

EPA-APS commented that the allowance requirements of

§§101.330-101.337 constitute a mass cap and trade program,

and that existing guidance for discretionary economic incentive

programs (EIPs) is found in 40 CFR Subpart U. The commenter

stated that draft federal guidance for EIPs was published in

the Federal Register on September 15, 1999, and that the

60-day public comment period ends on November 15, 1999.

EPA stated that the proposed allowance allocation/trading

program to meet SB 7 and the VERP program to meet SB 766

will be reviewed under EPA’s existing guidance if applicable,

ADOPTED RULES January 7, 2000 25 TexReg 137
and possibly under EPA’s new guidance (if finalized before the

state’s SIP submittal).

TUC, §39.264 requires the commission to create a mass

cap and trade system to distribute emission allowances for

use by grandfathered and electing EGFs. TUC, §39.264(g)

and (h) requires the commission to allocate allowances to

grandfathered EGFs in defined regions of the state. The specific

intent of SB 7 is that total annual emissions of NOx from

grandfathered EGFs will not exceed 50% of the NOx emissions

in 1997 as reported to the commission and that for coal-fired

grandfathered EGFs, the total annual emissions of SO2 will

not exceed 75% of the emissions during 1997, as reported to

the commission. The adopted rules provide the requirements

for both the permitting of these grandfathered EGFs, and an

emission banking and trading program. These rules were

proposed as a SIP revision to ensure that the reductions

obtained from the program are federally enforceable and thus

useful towards the reduction of criteria pollutant emissions

necessary to assist nonattainment and near-nonattainment

areas in meeting or continuing to meet the NAAQS. This

program was designed to comply with the legislative mandate of

SB 7 which in some ways is inconsistent with the requirements

for discretionary EIPs. However, the commission anticipates

adopting future SIP rules that will contain requirements that are

more consistent with the EIP. The commission is committed to

working with the EPA in its review and approval of the SB 7

program.

CPS commented that generally the proposed use and transfer

of allowances is too restrictive and beyond the intent of SB 7.

The commenter stated that the cap and trade program should

be flexible and not have undue restrictions, which do not allow

companies to make the necessary reductions in the most costeffective and efficient manner.

Pre-proposal drafts of the EBTA contained several restrictions

on trading to assist EGFs that are subject to 30 TAC Chapter 117 in meeting those SIP requirements. However, since

the proposed rules eliminated the references to Chapter 117,

the SIP-related restrictions were not proposed. The commission believes that the adopted rules provide flexibility for the

successful implementation of the EBTA and the permitting program. The restrictions that are in the adopted rules are primarily requirements of TUC, §39.264, for example, the limitation

on trading outside of the designated regions. Other restrictions,

such as the monitoring provisions or the reporting requirements,

are intended to provide assurance that the mandated emission

reductions are actually achieved. The commission does not believe that these minimum restrictions will inhibit free trading of

allowances among EGFs.

EPA-ARD commented that the banking and trading system

is too restrictive. EPA-ARD felt that greater freedom would

result in greater flexibility and cost savings without undermining

environmental goals. They recommended that the commission

consider that allowances can be banked indefinitely; however,

if banked emissions exceed 10% of capped emissions, then

banked allowances must be used at a rate of two allowances

per actual one ton emitted.

The rules have not been revised to make the suggested change

in response to this comment. The proposed §101.335(b), now

§101.335(a), provides that allowances not used for compliance

may be banked for use in subsequent control periods. This

program was designed to comply with the legislative mandate of

SB 7 which in some ways is inconsistent with the requirements

for discretionary EIPs. However, the commission anticipates

adopting future SIP rules that will contain requirements that are

more consistent with the EIP. The commission is committed to

working with the EPA in its review and approval of the SB 7

program.

EPA-ARD commented that the definitions in §101.330 do not

clearly define "electing" and "non-electing" EGFs and the

relationship to "grandfathered" facilities. It commented that

"grandfathered facility" is used without definition in Chapter 101.

The commission agrees, and has modified the definition of

"Electric generating facility" in §101.330(14) to include the term

"grandfathered." This modified definition now refers to electric

generating facilities that are required to obtain an EGFP. The

exemption in that definition has been moved to §101.331, Applicability. The commission has changed references to "grandfathered facilities" to "grandfathered EGFs." "Grandfathered facilities" is defined in Chapter 116. The definition of "nonelecting

EGF" is not necessary, and it has been deleted. The rule was

also revised to include a new definition of "electric generating

facility" in §101.330(12) to be used for generic references to

EGFs.

B&P commented that the definition of "Broker" in §101.330(4)

should be revised because it is unnecessarily vague and recommended that a "Broker" be defined as "A person not required

to participate in the requirements of this division who opens an

account under this division for the sole purpose of banking and

trading emissions allowances." B&P also recommended that the

definition of "Broker account" be revised to read "The account

where allowances held by a broker are recorded." The commenter also noted that conforming changes can be made to

§101.331, if the suggested changes are made.

The proposed rule did not include a definition of "Broker" in

§101.330(4); however, the commission agrees that a definition

is appropriate and has included one in the adopted §101.330(4).

Section 101.331(2) has been revised to reflect this new definition. The commission also agrees with the suggested change

to the definition of "Broker account" in §101.330(5), but has retained the second sentence regarding the use of allowances

held in a broker account.

B&P commented that the definition of "Compliance account"

does not fully distinguish a "compliance account" from a "broker

account." Therefore, the definition for "Compliance account"

should be revised to "The account where allowances held by an

EGF or multiple EGFs are recorded for the purposes of meeting

the requirements of this Division and Chapter 116, Subchapter

I of this title."

The commission agrees that the suggested language may

clarify the rule and has revised the definition of "Compliance

account" in §101.330(8) accordingly.

Baker & Botts commented that the definition of "Electric generating facility" should read as follows: "A facility that generates

electric energy for compensation and is owned or operated by

a person in this state, including a municipal corporation, or river

authority. An EGF does not include a facility that generates electric energy for internal use and that during 1997 sold, to a utility

power distribution system, less than one third of its potential

electrical output capacity or less than 25 MW output, whichever

is greater." Baker & Botts commented that this language more

clearly eliminates those units that were not intended to be cov25 TexReg 138 January 7, 2000 Texas Register
ered by SB 7, such as a 20 MW station that sells half of its

generated electricity (ten MW). The commenter also stated that

it is clearly not the intent of SB 7 to regulate this size/type of

source. TXU commented that the definition of "Electric generating facility" in §116.18(8) excludes "a facility that generates

electric energy primarily for internal use but that during 1997

sold to a utility power distribution system less than 1/3 of its potential electrical output capacity." TXU believes that if it were the

Legislature’s intent to exclude cogeneration facilities, language

would have been included in the definition found in §39.264(2).

In accordance with SB 7, any facility that generates electricity

for compensation should be included in the definition.

The commission has not revised the rule in response to

these comments. TUC, §39.264(a)(2) provides the definition

of an "electric generating facility." The SB 7 definition, and

the definition of EGF in §101.330 both contain the language

concerning the generation of electricity for compensation. The

commission believes that cogeneration facilities that sell less

than one-third of potential electrical output capacity to the utility

power distribution system are generating electricity primarily

for internal use and that any electricity that is sold to the

distribution system is surplus and not electric energy that was

originally generated for compensation. The commission agrees

that the definition of electric generating facility in SB 7 does

not specifically exclude these cogeneration facilities from the

requirements of SB 7, nor does it prohibit the commission from

revising the definition to exclude certain EGFs based on the

generation of electricity for compensation. The commission has

also excluded EGFs that generate power primarily for internal

use, but that during 1997 sold one-third of their generated

power or less than 219,000 megawatt-hours to the utility power

distribution system. The exemption was modified to also

exclude EGFs that sold less than 219,000 megawatt hours to

a utility power distribution system. This reference was added

to exempt small cogenerators who may exceed the one-third

limitation. The commission believes that excluding these EGFs

is consistent with SB 7 and will not negatively affect the overall

emission reductions required by the program. The commission

believes that an exclusion based on these criteria is sufficient

and is consistent with the EPA definition in 40 CFR §72.2.

AE questioned the reasoning of selecting May 1-April 30 as

the control period in §101.330(6). AE felt that this will lead

to difficulties associated with the calendar year being used

for emissions inventories, and recommended development of

a plan that transitions the control period to one that matches

the calendar year.

The rule has not been revised in response to this comment;

however, the definition of "Control period" is now in §101.330(9).

TUC, §39.264(c) provides "for the 12-month period beginning

on May 1, 2003, and for the 12-month period after the end

of that period, total annual emissions of nitrogen oxides from

facilities subject to this section may not exceed levels equal

to 50% of the total emissions of that pollutant during 1997,

as reported to the conservation commission, and total annual

emissions of sulfur dioxides from coal-fired facilities subject to

this section may not exceed levels equal to 75% of the total

emissions of that pollutant during 1997, as reported to the

conservation commission. The limitations prescribed by this

subsection may be met through an emissions allocation and

allowance transfer system described by this section." Because

§39.264(c) specifically defines the period of time to be used

as the control period, the commission does not believe it is

appropriate to use any different control period. The rule has

not been revised in response to this comment.

B&P commented that §101.330(9) does not clearly define EGFs

that are physically located in Texas. The commenter stated

that the definition, although consistent with TUC, §39.264(a)(2),

appears to encompass facilities not located in Texas so long

as they are owned by a person in Texas, and that the rules

should only apply to facilities that are physically located in Texas.

The current definition only states "EGFs owned or operated by

persons in this state." UT commented that §101.330(9) should

further define "person," since this term is used in TUC, §39.264

as "individual, partnership, a partnership of two or more persons

having a joint or common interest, a mutual or cooperative

association, and a corporation, but does not include an electric

cooperative." UT also commented that the definition of "person"

does not include state institutions of higher education.

The commission has not revised the rule in response to the

comment from B&P. Therefore, it is not necessary to clarify

that the rules only apply to EGFs that are physically located

within Texas. However, if the commission were to include such a

limitation, it might prohibit the commission from defining the "El

Paso Region" as being consistent with the La Paz Agreement.

The La Paz Agreement designated the Paso del Norte Air Shed

as the contiguous air shed basin between El Paso, Texas,

Sunland Park, New Mexico, and Ciudad Juarez, Chihuahua.

The La Paz Agreement does not extend the commission’s

jurisdiction into the State of New Mexico. Elsewhere in this

response to comments, the commission states its intent for

revising the definition of "El Paso Region" to be consistent with

the Paso del Norte Air Shed. If the commission were to limit

participation in the EBTA to only those EGFs that are physically

located in Texas, then it is unlikely, in spite of the La Paz

Agreement, that the El Paso Energy facility in Sunland Park,

New Mexico could obtain allowances.

The commission agrees that it is appropriate to use the

definition of "person" in TUC, §11.003(14) and has included a

new definition in §101.330(17) and §116.18(12). This definition

will apply for purposes of initial issuance of EGFPs and for

the allocation of allowances. By using this definition, the

commission can ensure that it will not inadvertently require

additional facilities to comply with the program, since the

definition of "person" in TCAA, §382.003(10) is more inclusive

than the TUC definition.

B&P commented that §101.330(12), now §101.330(16), should

define "NOx allowance" consistently with the proposed definition

of "SO2 allowance," which states that an SO2 allowance is

valid only for the purposes of meeting the requirements of this

division and Chapter 116, Subchapter I.

The commission agrees, and has revised the definition of

"NOx allowance" to be consistent with the definition of "SO2

allowance."

Enron requested that §101.332(f) be revised to provide that

neither a NOx allowance nor an SO2 allowance constitutes a

security or property right, but that they may be used as collateral

or security for indebtness.

The commission has not revised the rule in response to this

comment. The commission believes that the use of allowances

as collateral or to secure a debt is a matter best left to the owner

of the allowances and the party with whom the owner is dealing.

Since allowances can be reduced, such as when emissions

ADOPTED RULES January 7, 2000 25 TexReg 139
exceed the allowances in any control period, to account for load

shifting, or to invalidate allowances that were used by electing

EGFs to meet SIP requirements, it is likely that this sort of

provision would conflict with this statutorily based enforcement

authority. Nothing in the adopted rule or TUC, §39.264 prohibits

the use of allowances for collateral or security for indebtedness;

however, the commission does not believe that adding this

language to the rule is appropriate.

CPS commented that §101.332 restricts the use of allowances

for use only in the EBTA and prohibits the use of allowances

for netting, offsets, or other credits. The commenter stated

that it is unclear why these NOx allowances created for EBTA

cannot be used for other trading programs, and that it seems

that allowances created for use by utilities and used only within

the utility sector could be traded for any program designed to

reduce NOx from that sector. CPS further commented that for

example, trading should be allowed for future utility offsets if they

are not needed for the EBTA program, since the NOx reductions

are still reducing overall NOx from the same utility sector.

The commission has not revised the rule in response to this

comment. TUC, §39.264 contains several restrictions on the

use of allowances. TUC, §39.264(j) provides that EGFs may

only trade allowances with other EGFs in the same region.

TUC, §39.264(l) provides that an EGF may not trade an unused

allowance for a particular air contaminant, for use as a credit

for another air contaminant. TUC, §39.264(i) limits the use

of allowances for electing EGFs. The pre-proposal draft of

these rules did provide flexibility to EGFs that would also be

subject to Chapter 117 SIP requirements; however, the proposal

eliminated any links to Chapter 117. The general concern was

that the limitations necessary to ensure that the allowances

could be used for SIP purposes made the EBTA unwieldy

and overly restrictive. Further, there are additional federal

requirements that must be met in order for allowances to be

used for netting or offsets. In order to ensure that the EBTA

is implemented consistently with the requirements of TUC,

§39.264, the adopted rule contains the minimum restrictions on

trading. In the near future, the commission will be proposing

additional SIP reductions that will impact EGFs and other

sources in the affected areas. If it is appropriate, a trading

program could be developed for facilities affected by those rules

or the EBTA could be modified to accommodate EGFs that are

affected by the SIP rules at that time.

B&P commented that §101.332(a) states that allowances are

valid only for meeting the requirements of "this division" and

cannot be used to meet the limitations of a permit or applicable

rule. However, the proposed definition of "SO2 allowance"

states that allowances can be used to meet the requirements

of Chapter 116, Subchapter I. The commenter stated that

§101.332(a) should be revised to reflect that allowances are

valid for meeting the requirements of Chapter 116, Subchapter

I.

The commission agrees with the suggested change and has

corrected §101.332(a).

CSW, TXU, Entergy, AECT, CT&W, Group A, Entergy Services,

and CPS recommended that §101.332(b) be revised to provide

a 30-day period after the end of each control period for owners/

operators of EGFs to reconcile the allowance accounts, by

changing May 1 to June 1. Reliant requested a 60-day period

and suggested that the rule be revised to extend the period to

June 30. CSW and TXU also requested language clarifying

that this section should only apply to EGFs that are subject

to this division. SPS commented that the proposed language

was not clear, consistent, or reasonable relating to reconciliation

periods. SPS proposed that 60 days (consistent with Acid

Rain Program) would be acceptable for emission data to be

quality assured and for transfer transactions to be completed if

necessary.

The commission agrees that 30 days for EGFs to reconcile its

allowance account is appropriate and §101.332(b) has been

revised. The commission reminds EGFs that if additional

allowances are necessary but unavailable, the EGF will be

out of compliance with the requirements of the EBTA in the

EGFP. EGFs now have until June 1 after every control period

to sell or purchase allowances in order to reconcile the amount

of allowances in their compliance account to ensure that the

number of allowances in their account are equal to, or exceed,

the amount of emissions from the prior control period.

Reliant commented that §101.332(c) should be revised to allow

the creation of discreet emission reduction credits (DERC) for

those facilities that have early implementation of reductions

required under the EBTA program.

The commission agrees that early reductions that meet the

requirements of §101.29 could be banked as DERCs. Section

101.332(c) does not eliminate this possibility.

EPA-APS noted that §101.332(c) states that emissions reductions used to satisfy the requirements of the EBTA cannot be

used to generate emission reduction credits (ERC) or DERCs.

EPA-APS commented that since allowances may be banked

and traded annually, it would clarify the intent of this section to state that any emission control equipment installed or

other measures undertaken to not exceed the allowances in

the compliance account cannot be used for ERCs or DERCs

under TNRCC’s emissions banking and trading program found

in §101.29 or other banking/trading programs such as Chapter

117.

The commission has not revised the rule in response to this

comment. The commission agrees that reductions cannot be

used to meet the requirements of SB 7 and also be banked

as DERCs or ERCs because the reductions cannot be counted

twice. The commission will allow for reductions that are surplus

to either be banked as allowances or DERCs or ERCs, as long

as the reduction meets the requirements of §101.29, Emission

Credit Banking and Trading.

EPA-ARD asked whether "the emission reduction credits or

discrete emissions reductions credits are related to a particular

rule such as Chapter 117, Subchapter B, Division 2."

The DERCs and ERCs are related to a variety of rules, such

as 30 TAC Chapter 115, Control of Air Pollution from Volatile

Organic Compounds, and Chapter 117, Control of Air Pollution

from Nitrogen Compounds. Section 101.29 provides a complete

listing of uses for ERCs and DERCs.

EPA-ARD commented that §101.332(h) mentions two cases

where there would be one compliance account. It suggested

that language may be needed to address situations where there

are multiple EGFs at the same property, but not under common

ownership and control.

The commission agrees with the comment and has revised

the definition of "Compliance account" in §101.330(8) to clarify

25 TexReg 140 January 7, 2000 Texas Register
that EGFs not under common ownership or control may have

separate compliance accounts.

Lloyd Gosselink commented under §101.332(h) that facilities

with multiple EGFs should be allowed to have multiple compliance accounts, and that having one compliance account will

present practical problems because different EGFs may be under different regulatory requirements. For example, permitted

EGFs are currently required to report on an annual basis on January 1 of each year; however, grandfathered EGFs are required

to report on an annual basis ending on May 1 of each year.

The commenter stated that subsection (h) should be deleted

because of these problems.

The commission believes that assigning one compliance account for multiple EGFs under common ownership or control

will properly structure the allotment and tracking of allowances.

The reporting requirements for the control periods for electing

EGFs and grandfathered EGFs are the same. Any reporting requirements under Chapter 116, Subchapter B for electing EGFs

are based on a calendar year and are not associated with the

reporting requirements for the EBTA and Chapter 116, Subchapter I.

EPA-ARD commented that §101.332(i), while appropriate, may

not be sufficient to spur sources to comply. EPA-ARD asked

whether other penalty provisions apply.

The commission has not revised the rule in response to this

comment; however, the commission has moved §101.332(i)

to §101.333(4) for clarity. Section 101.330(i) is based on

TUC, §39.264(n)(2) and authorizes the commission to reduce

allowances for the next control period for an EGF that emits

an air contaminant in excess of the EGF’s allowances. In

addition to that provision, subsection (n) provides that the

commission may enforce administrative penalties in an amount

determined by the commission for each ton of emissions by

which the EGF exceeds its allowances. TUC, §39.264(o)

states that the commission can penalize an EGF that exceeds

its allowances by ordering the EGF to shut down or to take

other enforcement action as provided by commission rules.

The commission believes that these provisions are sufficient

to ensure compliance with the EGFPs and the EBTA.

SPS and Entergy commented that the database used to obtain

heat input values for calculation of NOx allowances should reflect

actual measurement of fuel combusted and added that the

EPA Acid Rain Database contains values that are generally

related to actual fuel consumption. SPS, Entergy, Group A, and

CPS commented that the same database should be applied to

both grandfathered and electing facilities. CT&W commented

that the proposed method for calculating emission allowances

using EPA’s Acid Rain Database in §101.333 is the most

accurate, and suggested that the commission make use of it

for all allowance calculations. CSW, Reliant, Brazos Electric,

Entergy Services, and AECT suggested that §101.333(2) be

revised to specify that the amount of allowances allocated to

electing EGFs will be equal to the actual emissions in tons in

the 1997 EPA Acid Rain Database, provided that the number

of tons do not exceed the allowable emissions in NSR permit

for that electing EGF or the maximum annual emissions under

any applicable state or federal requirement. CSW and Reliant

commented that this request is intended to make the calculation

of allowances on a consistent basis for all EGFs.

TUC, §39.264(h) specifies the formula to be used for the

calculation of allowances for grandfathered EGFs. That section

also specifies emission rates to be met within each region. As

stated in the proposal preamble, the 1997 Emissions Scorecard

from EPA’s Acid Rain Program is the basis of the emission rates

specified in TUC, §39.264(h) for grandfathered EGFs. These

emission rates are necessary to achieve the required 50%

reductions in NOx and 25% reductions in SO2

. The commission

agrees that it would be appropriate to use the EPA Acid Rain

Program Database as the basis for calculating allowances

for electing EGFs and has revised §101.333(2) to include a

reference to the 1997 Emissions Scorecard from EPA’s Acid

Rain Program.

Reliant commented that §101.333(1) should be clarified to state

that "ER = emissions rate, as defined in subparagraphs (C) or

(D) of this paragraph." Lloyd Gosselink commented that there

are problems with the sentence structure of §101.333(1). A

conjunction "or" follows the end of subparagraph (A), but not

subparagraph (B). Also, the equation formula legend includes

a reference to a subparagraph (E), which was not proposed.

EPA-APS also commented that §101.333(E) does not exist and

requested clarification by either adding the omitted subparagraph (E) or changing the definition of ER as the emission rate

defined in subparagraph (C) or (D). EPA-ARD commented that

in §101.333(1)(E), emission rates referenced in Chapter 117

should be more specific.

The commission agrees that the proposed §101.333(1) contained typographical errors and an erroneous reference to a

nonexisting subparagraph (E), and has revised the rule so that

it has the appropriate conjunctions, numbering, and lettering.

These changes are not substantive and have not changed the

meaning of the section.

EPA-ARD commented that it is not clear in §101.333(1) which

sources receive allocations under the first equation and asked

if it would be used for grandfathered facilities. EPA-ARD also

questioned whether the limits in §101.333(2) limit the allocation

in 101.333(1).

The commission has revised the rule to clarify that grandfathered EGFs are the facilities that are given allowances under

§101.333(1). The limits in §101.333(2) are applicable only to

electing EGFs to ensure that emission reductions used for the

EBTA are real and non-surplus.

EPA-ARD commented that §101.333(1)(A) and (B) is ambiguous when it refers to "Acid rain database." EPA-ARD suggested

that it would be clearer if the language specified "1997 Emissions Scorecard from EPA’s Acid Rain Program."

The commission agrees, and has revised the rule to refer to the

"1997 Emissions Scorecard from EPA’s Acid Rain Program."

The proposed §101.333(1)(A) and (B) have been deleted, and

the specification for the acid rain database is now in the formula

in §101.333(1) for heat input.

EPA-ARD commented in §101.333(1)(C)(ii) that it is unclear if

the 1.38 lb/mm BTU limit for SO2 applies to all EGFs, or only

coal-fired sources.

The commission agrees that this section was unclear and has

revised §101.333(1)(C)(iii), now §101.333(1)(A)(ii), to clarify that

the 1.38 lb/mm BTU limit for SO2 applies to only coal-fired

grandfathered EGFs.

EPA-ARD commented in §101.333(1)(D) that clarification is

needed for the emission rate used for SO2

.

ADOPTED RULES January 7, 2000 25 TexReg 141
The commission has made no changes in response to this

comment; however, §101.333(1)(D) has been moved to

§101.333(1)(B) for clarity. TUC, §39.264 did not specify an SO2

emission rate for grandfathered EGFs in the West Texas or the

El Paso Region, because there are no coal-fired grandfathered

EGFs in these regions.

AE and Lloyd Gosselink commented that there should be an alternative means for determining NOx

/SO2 allowance allocations

if the applicant can demonstrate that the base year (1997) was

an abnormal year for system operation. AE offered a possible alternative scenario: if the applicant could demonstrate that

the standard allocation, based on 1997 process values, was

more than 20% less than the average of the three-year period

of 1996 to 1998 inclusive, the average of these three years

would be the base allocation for that unit. Lloyd Gosselink proposed that the final rules include a component, for example, the

facility’s capacity factor for the year, to take into account actual

operating hours during the 1997 base year. The commenter

stated that this component will allow the TNRCC and the operator to extrapolate an annual emission rate based on the actual

emissions level and the actual operating hours for the facility

during 1997. Lloyd Gosselink proposed the following revision

to §101.333(1)(A): "HI = total heat input (million British thermal

units (MMBtu)) during 1997, determine by subparagraphs (a)

or (b) of this paragraph which may be adjusted to an annualized figure to account for unit outages and load growth." LP&L

commented that the use of maximum capacity during the past

five years of emissions data would allow for more competitive

flexibility while still meeting the intended emissions reduction

goal, and that by using one year of emissions data (1997) the

Legislature did not consider important aspects, such as load

swing (when a utility can purchase electricity cheaper than it

can produce it). The commenter stated that every generation

source that did not produce or had fewer production hours in

1997 will have its operational ability restrained with a reduction

in its ability to compete in a deregulated market. LP&L also

acknowledged that the requirement to base allowances on one

year of heat input data is a basic part of the legislation, and that

the commission is bound by this requirement.

The commission has made no changes in response to these

comments. TUC, §39.264(h) specifies that the commission

shall allocate allowances based on a facility’s total heat input in

terms of MMBtu during 1997. The commission believes that the

provisions of TUC, §39.264(h) do not provide the commission

with the discretion to create a different formula or emission rates

for the purpose of meeting the mandated reductions of 50% for

NOx and 25% for SO2

.

Lloyd Gosselink commented that §101.333(1)(A) conflicts with

the Electric Reliability Council of Texas (ERCOT) designation

of Garland’s utilities as "must run" facilities. This designation

requires Garland’s units to operate near capacity during the

summer months in order to provide adequate and reliable

electricity. The commenter stated that based on the proposed

language, Garland may be forced to reduce electric generation

in order to meet emission reduction mandates, possibly causing

brownouts during the summer months.

The commission has made no changes in response to this comment. ERCOT-designated "must run" grandfathered EGFs are

not among the exemptions from the requirements to operate

in compliance with the EBTA as prescribed by TUC, §39.264.

The commission does not believe that TUC, §39.264 requires

reductions in electric generation, since each grandfathered EGF

has the option of complying with SB 7 emission reduction requirements by installing emission controls, acquiring additional

allowances, or reducing electric generation. Further, electing

EGFs that are designated as "must run" facilities are not required to participate in the EBTA.

CSW, Entergy, AE, CEED, Entergy Services, Group A, AECT,

and CPS commented that §101.333(2) should allow the owner/

operator of electing EGFs to decide whether allowance(s)

should be allocated for NOx

, SO2, or both. By mandating that

an electing EGF obtain allowances for both NOx and SO2

, AE

felt that participation will be severely limited. CPS commented

that mandating electing facilities to obtain allowances for both

NOx and SO2

, will limit, rather than broaden, the range of

cost-effective alternatives available to utilities to achieve the

requirements of TUC, §39.264; and have no effect on achieving

compliance with the emissions limitations prescribed by TUC,

§39.264(c). CPS commented that it is not the intent of SB 7

to require additional limitations or reductions on emissions from

permitted facilities.

The commission has not revised the rule in response to this

comment. The commission believes that the language in TUC,

§39.264(i) requires electing EGFs to be given allowances for

both NOx and if applicable, SO2

. TUC, §39.264(i) provides

that "a person, municipal corporation, electric cooperative or

river authority that is not covered by this section may elect to

designate that facility to become subject to the requirements

of this section and to receive emissions allowances for the

purpose of complying with the emissions limitations prescribed

by Subsection (c)." TUC, §39.264(i) refers to the emission

limitations in TUC, §39.264(c). TUC, §39.264(c) provides

"for the 12-month period beginning on May 1, 2003, and

for the 12-month period after the end of that period, total

annual emissions of nitrogen oxides from facilities subject to

this section may not exceed levels equal to 50% of the total

emissions of that pollutant during 1997, as reported to the

conservation commission, and total annual emissions of sulphur

dioxides from coal-fired facilities subject to this section may

not exceed levels equal to 75% of the total emissions of

that pollutant during 1997, as reported to the conservation

commission. The limitations prescribed by this subsection may

be met through an emissions allocation and allowance transfer

system described by this section." TUC, §39.264(c) also refers

to "facilities subject to this section." The phrase "this section" in

TUC, §39.264(i) refers to TUC, §39.264 in its entirety and not

to the specific requirements of subsection (i). Thus, if an owner

or operator elects to designate an EGF to "become subject

to the requirements of this section and to receive emissions

allowances for the purpose of complying with the emissions

limitations prescribed by Subsection (c)," the electing EGF

is now subject to all of the applicable requirements of TUC,

§39.264, including the requirements of TUC, §39.264(c). Since

TUC, §39.264(c) requires specific reductions of NOx and SO2

,

electing EGFs will be given allowances consistent with the

requirements of TUC, §39.264(i) for the purpose of meeting

the emission reductions required by TUC, §39.264(c). Because

the commission believes that the language in TUC, §39.264(i)

requires electing EGFs to be given allowances for both NOx

and if applicable, SO2, the adopted rule has not been revised in

response to the comments.

EPA-APS commented that §101.333(2)(C) should be revised to

state that the amount of allowances for electing EGFs shall not

exceed an applicable state or federal requirement. The com25 TexReg 142 January 7, 2000 Texas Register
menter stated that a federal requirement may include, but not

be limited to, reasonably available control technology (RACT)

and/or reductions from sources in an ozone nonattainment area

or any or all portions of the Texas Clean Air Strategy area

contained in an emissions inventory utilized in an attainment

demonstration which has been submitted to the EPA for approval as part of a SIP.

The commission agrees that the amount of allowances for electing EGFs may not exceed applicable state and federal requirements. The commission believes that the proposed language in §101.333(2)(c) addressed this issue. The adopted rule

has not been revised in response to this comment; however,

§101.333(2)(C) is now in §101.333(2)(B). Nothing in §39.264

limits the allowances for electing EGFs to ozone nonattainment

area or any or all portions of the Texas Clean Air Strategy area

contained in an emissions inventory utilized in an attainment

demonstration which has been submitted to the EPA for approval as part of a SIP. Therefore, the commission does not

believe that revising the rule to include these limitations is necessary.

EPA-APS commented that a new §101.333(2)(D) should be

added to state that for electing EGFs located in ozone nonattainment areas, the amount of allowances shall not exceed the

1990 emissions inventory or the emissions reported in any Rateof-Progress SIP submitted for the ozone nonattainment area, or

the emissions based on limitations established by regulations in

the attainment demonstration SIP.

The commission has not revised the rule in response to this

comment. TUC, §39.264(i)(2) provides that allowances for

electing EGFs shall be allocated in an amount equal to each

facility’s actual emissions in tons in 1997. TUC, §39.264(i)(4)

allows emission reductions from electing EGFs to be used

to satisfy emission reductions for grandfathered EGFs to the

extent that reductions used to meet TUC, §39.264(c) are beyond

the requirements of any other state or federal standard, or

both. However, nothing in §39.264 limits the allowances for

electing EGFs to 1990 emissions inventory or the emissions

reported in any Rate-of-Progress SIP submitted for the ozone

nonattainment area. Therefore, the commission does not

believe that revising the rule to include these limitations is

necessary.

CSW, Reliant, TXU, Entergy, Entergy Services, Group A, AECT,

and CPS requested that §101.333(3) be deleted. CSW, TXU,

AECT, and Entergy also requested that the statement in the

preamble that future rulemakings addressing future ozone SIP

reductions will reduce the allowances allocated under SB 7 be

deleted. CSW and Reliant commented that these allowable

reductions are contrary to the intent of §39.264 of SB 7,

are unwieldy, and are unfair to grandfathered facilities. CSW

and Reliant also commented that the allowance allocation and

trading provisions in SB 7 are a limited-purpose mechanism

for implementing a cap and trade program to allow flexibility

in achieving regional reductions of NOx and SO2

, and not an

all-purpose system for limiting emissions for grandfathered and

electing EGFs. CSW and Reliant commented that the SB

7 allowance system should remain distinct from the ozone

SIP and any other applicable requirement. Brazos Electric

suggested substitute wording that would track the language of

TUC, §39.264(s): "This section does not limit the authority of

the conservation commission to require further reductions of

nitrogen oxides, sulphur dioxides, or any other pollutant from

generating facilities subject to this section or Section 39.263."

The commission has deleted the proposed §101.333(3) because the proposed rule did not provide for allowing facilities

subject to Chapter 117 to use the EBTA program. The adopted

§101.333(3) implements §39.264(i)(4) to prevent double counting of emissions reductions by allowing the commission to invalidate allowances, authorizing emissions in excess of applicable

state or federal requirements that are allocated to an electing

EGF. This is necessary to account for state and federal regulations that became effective during the prior control period and

for regulations that specify emission rates instead of an emission cap. The commission has revised the adopted preamble

to reflect the fact that the trading program for future ozone SIP

requirements has not yet been developed. The proposed rule

did not include limitations that would be necessary to allow the

EBTA to be used as a SIP trading program. The commission

believes the adopted rule is consistent with the requirements of

§39.264.

EDF commented that §101.333(4)(B) requires the TNRCC to

allocate allowances annually, but that TUC, §39.264(h) implies

that the intent was to allocate allowances only once no later than

January 1, 2000. EDF believes that allocating allowances every

year is labor-intensive and unnecessary, since the allocation will

always be based on 1997 values, regardless if allocated once

or every year. EPA-ARD commented that §101.333(4)(C) is

unclear on whether the allowance allocations are permanent,

and recommended allocating allowances for a few years at a

time to allow EGFs to plan for compliance.

The commission agrees that allowances should be allocated

only one time and has revised §101.333(5)(C) to state that

allowances for a grandfathered or electing EGF shall be the

same as their initial allocations and that compliance accounts

will be automatically updated at the beginning of each control

period. However, §101.333(6) provides that after the annual

update to the compliance accounts, the number of allowances

may be adjusted after the commission reviews the final trading

reports required by §101.336. The commission must be able

to adjust allowances in order to implement certain provisions

of TUC, §39.264. For example, §101.332(i), which is based

on TUC, §39.264(n), provides that the penalty for exceeding

allowances allocated in a prior control period is to reduce

allowances for the next control period in an amount equal

to the emissions exceeding the allowances in the compliance

account. Other examples include a facility that volunteers to

permanently reduce the number of annual allowances allotted

to its compliance account in order to generate DERCs or ERCs,

allowances for electing EGFs that are reduced to comply with

other state and federal regulations, and allowances that are

reduced for electing EGFs that reduce utilization or shut down.

CSW commented that §101.333(4)(C) should be revised to

require the TNRCC to allocate allowances for electing EGFs

through rulemaking rather than orders.

The commission has made no changes in response to this

comment. TUC, §39.264(f) requires the commission to develop

rules to provide for the allocation of allowances. It does

not require the specific allowances for each affected EGF to

be stipulated in the rules. The commission believes that it

is sufficient to establish in the rule the procedure by which

allowances will be allocated. Additionally, the commission’s

using an order to allocate allowances will provide a less

resource-intensive method to allocate or revise as necessary

allowances for affected EGFs.

ADOPTED RULES January 7, 2000 25 TexReg 143
TXU, Lloyd Gosselink, and CEED commented that §101.333(5)

should be revised to eliminate the requirement that the registry

include the price paid per allowance. Omitting the price paid for

allowance is consistent with the EPA Acid Rain Program, and

including the price on the registry could actually inhibit trading.

The commission has made no changes in response to this

comment. The commission believes that including the price

paid per allowance in the registry will improve trading and selling

of allowances by providing an open and competitive market

system. Providing as much information as possible in the

registry will allow participants in the EBTA to make informed

transactions. For organizational clarity, §101.333(5) has been

renumbered to §101.333(7).

CPS commented that SB 7 language states that electing EGFs

cannot transfer allowances created by "reduced utilization or

shutdown." CPS believes that this language was included

to prevent companies from reducing their power output to

produce excess allowances. The commenter stated that the

formulas provided in §101.334 are overly complicated and do

not seem to accomplish this purpose. The commenter further

stated that the formulas include emission factors instead of just

restricting the basis to utilization, and they do not account for

generation that results from the replacement of thermal energy

from other units as allowed in SB 7. CPS believes that the

formulas should be deleted and each utility should be handled

on a case-by-case basis, because each utility has unique

circumstances under which it will replace lost energy. CSW,

Entergy Services, and AECT commented that §101.334(e)(2)

and §101.335(a) need to include the exception language from

TUC, §39.264(i)(3). CSW commented that the formulas and

remaining language in §101.334(e) conflict with §39.264(I)(3)

and that §101.334(e) must be revised. TXU commented that

SB 7 does not prohibit trading of allowances caused from

reduced utilization or shutdown, but proposed that §101.334

and §101.335 have tighter restrictions. TXU recommended

that §101.334 and §101.335 be revised to allow transfers

and banking of allowances resulting from reduced utilization

or shutdowns as long as the reduced utilization or shutdown

results from the replacement of thermal energy from the electing

EGF with thermal energy generated by any other EGF. Entergy,

Group A, and CPS commented that the use and transfer of

allowances should be in accordance with the requirements

and language of SB 7 and should be no more restrictive than

provided by law. EPA-APS commented that the term "reduced

utilization" in §101.334(e) is not clearly defined. The commenter

stated that for some, it may mean having less heat input to

the emissions unit than in 1997, and for others, it may mean

generating less electricity at the emission unit than in 1997.

Still for others, it may mean operating for fewer hours during

the year than in 1997. Others may consider that operating at

a reduced load factor (say at 75% for the year compared to

85% in 1997) is reduced utilization. EPA-APS recommended

including a definition of "Reduced utilization" in §101.330, or

revising §101.334(e) to state that allowances at electing EGFs

that result from reduced utilization, which means an emission

unit operating for fewer hours during the control period than it

did in 1997 (or other appropriate meaning) or shutdowns, are

ineligible for transfer.

TUC, §39.264(i)(3) specifies that an electing EGF may not transfer or bank allowances conserved as a result of reduced utilization or shutdown, unless the reduced utilization or shutdown

results from the replacement of thermal energy from the electing EGF with thermal energy generated by any other EGF. The

equations in the proposed §101.334(e) were to be used to calculate the number of the annual allowances allocated to an

electing EGF that would be eligible for trading or banking. The

commission agrees that these equations did not completely address the intent of SB 7 with regard to reduced utilization or

shutdown of electing EGFs. Accordingly, the equations have

been revised in the adopted §101.334(1), (2), and (3) to allow

the calculation of the number of allowances that will be deducted

from an EGF’s compliance account for emissions that occurred

during each control period.

The equation in §101.334(1) will be used for all grandfathered

EGFs, and for electing EGFs with equal or increased utilization

(i.e., the heat input for the control period equaled or exceeded

the heat input for 1997). In this case, the number of allowances

deducted from the compliance account will equal the number of

tons of actual emissions during the control period.

The equations in §101.334(2) and (3) will be used for electing

EGFs with reduced utilization for the control period (i.e., the

heat input for the control period was less than the heat input

for 1997). For these cases, the commission agrees that

determining the appropriate equation to use should be done

on a case-by-case basis.

The equation in §101.334(2) will be used for cases where

the reduced utilization or shutdown was not replaced by thermal energy generated by another unit. In accordance with

§39.264(i)(3), allowances will be deducted from the compliance

account to reflect what emissions from the electing EGF would

have been using 1997 heat input.

The equation in §101.334(3) will be used for cases where the

reduced utilization or shutdown was replaced by thermal energy

generated by another EGF. In these cases, allowances will be

deducted from the compliance account for each ton of actual

emissions, if any, from the electing EGF for the control period.

In addition, allowances will also be deducted from the electing

EGF’s compliance account for each actual ton of emissions that

result when the displaced thermal energy is generated by the

other EGF. In cases where the EGF to which the thermal energy

was transferred can be identified, the emission factor for that

EGF will be used in determining the allowances to deduct. This

allows the electing EGF to keep more allowances if the thermal

energy is transferred to an EGF with a low emission factor. In

those cases where the EGF to which the thermal energy was

transferred cannot be identified, the thermal energy is assumed

to be transferred to various EGFs in the state. As an estimate of

emissions in this case, the equation uses the average emission

factor for the state based on the 1997 Emissions Scorecard for

the EPA Acid Rain Program. Using the state average emission

factor encourages decreased utilization of electing EGFs that

have a higher emission factor than the state average.

EPA-ARD asked, concerning §101.334(e)(1), whether the equation is necessary when the heat input for the control period is

greater than that of 1997. EPA-ARD also asked whether the

emission factor in §101.334(e)(1) and (2) is a measured emission rate in pounds/MMBtu and if so, from which sources of

information. The commenter then asked if the equations could

ever yield negative numbers and if so, what a negative result

would mean.

The provisions of the proposed §101.334(e) were revised and

are now in §101.334(2) and (3) for organizational clarity. The

commission believes that because the heat input and emission

25 TexReg 144 January 7, 2000 Texas Register
factors can fluctuate, the formula is necessary to accurately

determine the amount of allowances, if any, that can be

transferred. A negative result indicates that actual emissions

exceeded allocated allowances; therefore, no allowances are

available for trading, unless additional allowances have been

purchased. The commission agrees that clarification needs to

be added as to the source of the emission factors and has

revised §101.334(e)(1) and (2) and §116.914(e) accordingly.

Brazos Electric commented that §101.334 restricts transfer of

allowances more than contemplated by the language of SB 7.

The commenter stated that specifically, TUC, §39.264 makes

no requirements for "authorized account representatives," prohibitions on transfers before May 1, 2003, or the tables of allowances set forth in §101.334(e)(1) and (2).

In order to ensure that the allowances allocated to each participating EGF are properly tracked and traded, the commission

believes that it is necessary to designate an individual or individuals who have the recognized authority to transfer and manage

allowances. This designation is necessary for the commission

to ensure that transfers are valid and not fraudulent. The commission does not believe that this is a restriction on the trading

program that will inhibit trading. The proposal stated that the

delay in the start of the trading program was necessary to allow

sufficient time to develop a tracking system for the transfer of

allowances. Further, the commission expects to adopt SIP revisions that will require additional emission reductions from EGFs

in attainment and nonattainment areas. The commission anticipates that these future SIP reductions may impact the EBTA

and that it would be premature to allow for actual trading to begin prior to the adoption of the SIP regulations. The commission

understands the need to begin planning for trades and does not

believe that the restriction on actual trading will prohibit EGFs

from creating contracts or other agreements that will be used

for trading after the start of the program. The commission’s response concerning §101.334(e) is addressed elsewhere in this

response to comments.

Brazos Electric commented that while TUC, §39.264(j) restricts transfer of allowances between regions (as proposed in

§101.334(f)), an exception should be made for transfers within

the same company:

The commission has made no changes in response to this

comment. TUC, §39.264(j), states that allocations (allowances)

can only be traded within the same region. Therefore, trading

cannot be made between regions, even if they are within

the same company. However, companies that have multiple

locations within the same region are not prohibited from trading

with each other.

Sierra Club commented that trading should be limited to the

same airshed, the same nonattainment area, and the same

area of influence affecting the nonattainment area so that the

trades pass the "laugh test."

The restrictions on trading are consistent with the requirements

of TUC, §39.264, which defines specific regions of the state and

limits trading of allowances to EGFs within the same region.

TUC, §39.264 does not include any restrictions on trading with

regard to nonattainment areas or airsheds.

TXU commented the reductions from electing EGFs may be

used only to the extent that they are beyond the requirement

of any other state or federal standard and that this provision

does not change the allowance allocation, it only restricts how

many allowances can be transferred from electing EGFs to other

EGFs. TXU suggested that §101.334 could be revised to add

a restriction in the transfer of allowances from electing EGFs to

other EGFs.

The commission has made no changes in response to this

comment. TUC, §39.264(i)(4) allows emission reductions from

electing EGFs to be used to satisfy emission reductions for

grandfathered EGFs to the extent that reductions used to meet

TUC, §39.264(c) are beyond the requirements of any other

state or federal standard, or both. The commission believes

that allowances that are allocated to an electing EGF that

authorize emissions in excess of applicable state or federal

requirements must be invalidated to prevent reductions from

being counted twice. Section 101.333(3) was revised to

allow the commission to invalidate allowances allocated to

electing EGFs that authorize emissions beyond state or federal

requirements.

Reliant commented that §101.334(a) should be revised to read

as follows: "Allowances may be transferred at any time after

May 1, 2003," and suggested deleting the phrase "during the

control period."

The adopted version of §101.334 is a new section called "Allowance Deductions." Some of the portions of the proposed

§101.334 have been moved to §101.335, now called "Allowance, Banking, and Trading." The former §101.334(a) is now

in §101.335(b). New §101.335(b) provides that allowances may

be transferred at any time during a control period. This subsection is intended to define the time period for transfers, not the

time period for the beginning of the EBTA program. That issue

is addressed in the new §101.335(c).

EPA-ARD commented that there appears to be a contradiction

in the required notification date for transfer of allowances.

Section 101.334(b) allows a facility to document a transfer

no later than June 30 following the control period. Section

101.334(d) requires notification within 30 days after the transfer,

and §101.332(b) requires all transfers to be done by May 1.

B&P commented that proposed language in §101.334(b) and

(d) and §101.336(b) includes three separate documentation,

notification, and reporting requirements. The commenter stated

that TNRCC should delete §101.334(b), because TNRCC

will already have received notification of all transfers under

§101.334(d). If §101.334(b) is not deleted, it should be revised

to allow documentation of final transfers and the emissions

report be submitted on June 30. EPA-ARD commented in

§101.334(b) that 60 days is sufficient to finish transfers and

submit notification. Reliant commented that §101.336(b) should

be revised to allow the report to be submitted by August 1 of

each year instead of June 1.

In the new §101.335(b)(2), the commission requires notification within 30 days of transfer for timely maintenance of compliance account records. The 60-day notification required in

§101.334(b), now located in §101.336(b), will serve as confirmation that the transfers of which the commission received notification under §101.335(b)(2), formerly §101.334(d), occurred,

and will allow the commission to timely reconcile all compliance

accounts. The commission has modified §101.336(b) to allow

final reports to be submitted no later than June 30 following the

control period. The commission believes that submittal of these

reports as quickly as reasonably possible is critical to expedite

the review and reconciliation of compliance accounts to allot alADOPTED RULES January 7, 2000 25 TexReg 145
lowances for the next control period. The commission believes

that 60 days is a reasonable time frame for this purpose.

EPE commented that the allowance mechanism under SB 7

should be consistent with the allowance transaction mechanism

used under Part 75 and the Acid Rain Program. EPE also

commented that the frequency of allowance reporting should

match the reporting of allowances and emissions under the Part

75 rules.

The commission believes that the allowance and reporting

requirements are consistent with the control period required by

TUC, §39.264. Further, the requirement to report after each

trade and the reconciliation period will allow the commission

to maintain an up-to-date registry consistent with the control

period. The rules have not been changed in response to this

comment.

EPA-ARD commented that subsections (a), (b), (d), and (e) in

§101.334 could be reorganized or combined for clarity. EPAARD also commented that §101.334(a) and (d) do not clarify

who may transfer allowances and who must notify whom of the

transfers.

As stated previously, most of the provisions in §101.334 have

been moved to §101.335 for clarity and organization. The

commission agrees that the rule was unclear as to who may

transfer allowances and who is being notified about transfers.

The rule has been revised to clarify that allowances are

transferred by authorized account representatives and that

notification of transfers of allowances must be provided to the

commission. Section 101.334(a) is now §101.335(b). Section

101.334(b) is now §101.336(b). Section 101.334(c) is now

§101.335(b)(1). Section 101.334(d) is now §101.335(b)(2).

Section 101.334(f) is now §101.335(d), and §101.334(g) is now

§101.335(e).

B&P commented that §101.334(d) states that allowance transfers are prohibited prior to May 1, 2003, and that this is justified

in the proposed preamble to allow the TNRCC to create the

appropriate tracking system. The commenter stated that there

does not appear to be any justification for prohibiting allowance

transfers for more than three years after the initial allocation

of allowances; thus, B&P recommended that §101.334(d) be

modified to allow transfers soon after January 1, 2000 (recommended six months after).

The commission has not made changes in response to this

comment; however, §101.334(d) is now §101.335(b)(2). The

proposal stated that the delay in the start of the trading

program was necessary to allow sufficient time to develop a

tracking system for the transfer of allowances. Further, the

commission expects to adopt SIP revisions that will require

additional emission reductions from EGFs in attainment and

nonattainment areas. The commission anticipates that these

future SIP reductions may impact the EBTA and that it would

be premature to allow for actual trading to begin prior to the

adoption of the SIP regulations. The commission understands

the need to begin planning for trades and does not believe that

the restriction on actual trading will prohibit EGFs from creating

contracts or other agreements that will be used for trading after

the start of the program.

B&P commented that §101.334(f) should be revised to clarify

that EGFs in the El Paso Region can use credits obtained from

Juarez, Mexico, as provided in proposed §101.337(a).

The commission has not revised the rule in response to this

comment. Section §101.334(f), now §101.335(d), provides that

allowances may not be transferred between regions. Section

§101.337(a) provides that an EGF in the El Paso Region can

meet the emission allowances by using credits obtained from

reductions in the City of Juarez, United States of Mexico. Elsewhere in the response to comments in this adopted preamble,

the commission states its intent for revising the definition of "El

Paso Region" to be consistent with the Paso del Norte Air Shed.

The Paso del Norte Air Shed includes the City of Juarez and

Sunland Park, New Mexico. Since the El Paso Region will be

defined to include the City of Juarez, it is not necessary to revise the new §101.335(d).

EPA-ARD commented that in §101.334(h)(1)(C) and (K), allowances will need to be tagged (region, nonattainment status,

grandfathered, permitted, etc.), in order for brokers and buyers

to know whether they are following the restrictions of trading.

The subparagraphs to which EPA-ARD refers were not included

in the proposed rules. However, allowances will be tracked

and recorded by the TNRCC. The allowance registry will note

the original owner of the allowances, the location of the EGF,

whether the allowance was allocated to a grandfathered or

electing EGF, and all other pertinent information to support the

EBTA.

SPS commented that if the TNRCC must reconcile emissions to

an annual cap each year, there will have to be compensation for

excess allowances that must be retired. The commenter also

stated that the TNRCC would have to establish some type of

buy-back program to limit the available allowances in any given

year.

The commission has made no changes to the rules in response

to this comment. Previous drafts of §101.335 limited the life of

allowances to one year. The adopted §101.335(b) provides that

allowances not used for compliance may be banked for use in

subsequent years. Thus, the commission does not believe that

the change would be needed because allowances do not expire.

PC commented that in §101.335 the commission should give an

incentive to utilities to retire their oldest plants or to go further in

reducing emissions by modifying §101.335 to allow owners of

grandfathered power plants to bank for two years any reductions

resulting from the retirement or extra cleanups. PC added that

additional years of credit should be given for EGFs that make

additional reductions, like three years for a permitted power

plant and five years on a retired power plant.

Although electing EGFs may not transfer or bank allowances

that are conserved as a result of reduced utilization or shutdown, grandfathered EGFs are not subject to the same limitation. Therefore, utilities have an incentive to shut down

grandfathered EGFs, because they are allowed to keep the allowances in perpetuity. Section 101.335(a) already provides

that allowances not used for compliance may be banked for

use in subsequent years. There is no limitation in the adopted

rule on the amount of time that allowances may be banked.

The commission believes that the adopted rule contains the incentive for grandfathered EGFs to be retired or make additional

reductions.

EPA-ARD commented that in §101.335(a), the term "electing

facilities" should read "electing EGFs." B&P commented that

there are several instances in the proposed rules where the

25 TexReg 146 January 7, 2000 Texas Register
undefined term "electing facilities" is used rather than the

defined term "electing EGFs."

The commission agrees, and has revised all references to

"electing facilities" throughout Chapter 101 to "electing EGFs."

The provision in §101.335(a), concerning "electing facilities" and

"reduced utilization or shutdown" was deleted, because the new

formulas in §101.334(2) and (3) address the issue.

EPA-ARD questioned why §101.335(b) limits banking to one

year, and stated that this may reduce the incentives for overcomplying with the program. SPS commented that no restrictions should be placed on allowances except those specifically

mentioned in SB 7. The commenter also stated that SB 7 does

not limit the life of an allowance; in fact, §39.264(k)(2) refers

to using allowances in later years (plural). Reliant commented

that §101.335(b) should be revised as: "Allowances not used

for compliance during a control period may be banked for use

in subsequent control periods." The commenter stated that this

change clarifies that allowances may be banked and used in

subsequent control periods. The word "years" may lead to confusion, since "control periods" is the term used throughout the

proposal.

The proposed rule did not contain a limitation in §101.335(b),

now §101.335(a), concerning the number of years the allowances could be banked. The commission agrees that the

word "years" should be deleted from the new §101.335(a) and

has revised the rule to refer to "control periods."

EPE and CT&W commented that in §101.337(a), the intent

of the Legislature was to include Ciudad Juarez, Mexico,

Sunland Park, New Mexico, and El Paso County as the

contiguous geographic area where an EGF may meet the

emission allowances by using credit from emissions reductions

achieved anywhere in the contiguous airshed, provided that

certain criteria are met.

The commission has revised the definition of "El Paso Region"

in §101.330(13) to include Ciudad Juarez, Mexico, and Sunland

Park, New Mexico. CT&W provided with its comments a copy

of the May 20, 1999 House Journal, "CSSB 7 - Statement

of Legislative Intent," in support of its contention that the

Legislature considered the purpose of the La Paz agreement

as supporting the legislative intent for SB 7. That statement

says in part that "The Act officially designated the Paso del

Norte Air Shed as the contiguous air shed basin between El

Paso, Texas, Sunland Park, New Mexico, and Ciudad Juarez,

Chihuahua." TUC, §39.264(g) provides that the El Paso Region

includes El Paso County. There is no express prohibition in

TUC, §39.264(g) that prevents the commission from defining

the El Paso Region as also including Ciudad Juarez, Mexico,

and Sunland Park, New Mexico. The inclusion of Sunland Park,

New Mexico will give further effect to the specific provisions

of TUC, §39.264 concerning the El Paso Region, since it will

provide EPE with additional options for meeting the emission

reductions required for the El Paso region.

EPE and B&P commented on §101.337(a) that creditable

reductions from Juarez are not limited to reductions from EGFs

and asked the commission to confirm this position.

The commission agrees that creditable reductions from Juarez

are not limited to reductions from EGFs. Since the rule as

proposed does not limit creditable reductions from Juarez to

EGFs only, no changes were made to the adopted §101.337(a).

CT&W commented that §101.337(a)(1)(A) should be revised

to add language to clarify how reductions in Mexico will be

enforceable. The commenter suggested that this intent could

be met by adding a special provision to EPE’s permit related to

a contemplated or proposed emissions reduction from Ciudad

Juarez. In that way, the commission will be able to enforce

EPE’s performance of that emission reduction project. CT&W

stated that if the commission is unwilling or unable to interpret

and apply the provision regarding Ciudad Juarez in this manner,

it should be deleted.

The commission believes that the enforcement issues concerning ERCs from the City of Juarez would best be addressed on

a case-by-case basis. This could be done through the use of

special conditions in EGFPs as allowed by §116.913(b). By not

including limitations in the adopted rule concerning the enforcement of emission reductions in the City of Juarez, EGFs in the

El Paso Region can propose new and innovative strategies to

obtain reductions from facilities in the City of Juarez. Thus, the

commission does not believe that it is appropriate to revise or

delete §101.337(a)(1)(A), since the reductions must be enforceable.

B&P commented that §101.337(a)(1)(B) requires emissions reductions in Juarez to be permanent, meaning that the emission

reduction is unchanging for the remaining life of the source. The

commenter stated that because an emission reduction could be

"permanent" even though it changes (the emission reduction

could increase), the definition should be revised by removing

the statement that "permanent" means unchanging.

The commission has made no changes to the rule in response

to this comment. If additional reductions are made, they would

be considered to be a new reduction. Any reductions relied

upon for an allowance would have to remain unchanged and

permanent.

EPE, B&P, and CT&W commented that §101.337(b) exempts

EGFs in the El Paso Region if the TNRCC determines that NOx

reductions in the area would result in an increased ambient

ozone level. The TNRCC states in the proposed preamble

that the NOx waiver (§182(f)) that has been granted for the El

Paso Region does not satisfy the criteria of this section. The

commenter stated that this interpretation is not consistent with

legislative intent and should be corrected.

TUC, §39.264(q) requires that the commission or EPA demonstrate that reductions in NOx would result in an increase in ambient ozone levels in order to be exempt from the NOx reduction

requirements of §39.264. Neither the EPA nor the commission

have made this determination. The §182(f) waiver indicates

that NOx reductions have not been shown in a SIP to be necessary for the attainment of the federal ozone standard. This

is not equivalent to saying that NOx reductions will cause an increase in ozone levels; therefore, the commission believes that

the NOx reduction requirements of TUC, §39.264 apply in El

Paso County and has not changed the rule.

STATUTORY AUTHORITY

The new sections are adopted under TUC, §39.264, which

authorizes the commission to develop rules for the allocation

of emission allowances to EGFs and to make rules concerning

the banking and trading of those allowances. The new sections

are also adopted under Texas Health and Safety Code, TCAA,

§382.011, which authorizes the commission to administer the

requirements of the TCAA; §382.012, which provides the

ADOPTED RULES January 7, 2000 25 TexReg 147
commission with the authority to develop a comprehensive plan

for the state’s air; §382.017, which authorizes the commission

to adopt rules consistent with the policy and purposes of the

TCAA; §382.023, which authorizes the commission to issue

orders; and §382.061, which authorizes the commission to

delegate permitting authority to the executive director; and

Texas Water Code, §5.122, which authorizes the commission

to delegate uncontested matters to the executive director.

§101.330. Definitions.

The following words and terms, when used in this division, shall

have the following meanings, unless the context clearly indicates

otherwise.

(1) Allowance–The authorization to emit one ton of

nitrogen oxides (NOx

) or sulfur dioxide (SO2) during a control period.

(2) Authorized account representative–The responsible

person who is authorized, in writing, to transfer and otherwise manage

allowances.

(3) Banked allowance–An allowance which is not used to

reconcile emissions in the designated year of allocation, but which

is carried forward into future years and noted in the compliance or

broker account as "banked."

(4) Broker–A person not required to participate in the

requirements of this division who opens an account under this division

for the purpose of banking and trading emissions allowances.

(5) Broker account–The account where allowances held

by a broker are recorded. Allowances held in a broker account may

not be used to satisfy compliance requirements for this division.

(6) Coal–All solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society for Testing

and Materials Designation ASTM D388 92 ’’Standard Classification

of Coals by Rank’’ (as incorporated by reference in Title 40 Code of

Federal Regulations, §72.13 (effective June 25, 1999)).

(7) Coal-fired–The combustion of fuel consisting of coal

as defined in paragraph (6) of this section or any coal-derived fuel

(except coal-derived gaseous fuels with a sulfur content no greater

than natural gas), alone or in combination with any other fuel. The

definition is independent of the percentage of coal or coal-derived

fuel consumed during any control period.

(8) Compliance account–The account where allowances

held by an EGF or multiple EGFs are recorded for the purposes of

meeting the requirements of this division and Chapter 116, Subchapter

I of this title (relating to Electric Generating Facility Permits).

EGFs not under common ownership or control may have separate

compliance accounts.

(9) Control period–The 12-month period beginning May

1 of each year and ending April 30 of the following year. Control

periods begin May 1, 2003.

(10) East Texas Region–All counties traversed by or east

of Interstate Highway 35 north of San Antonio or traversed by

or east of Interstate Highway 37 south of San Antonio, and also

including Bexar, Bosque, Coryell, Hood, Parker, Somerville, and

Wise Counties.

(11) Electing EGF–An electric generating facility permitted under Chapter 116, Subchapter B of this title (relating to New

Source Review Permits) which is not subject to the requirements of

Texas Utility Code, §39.264 and elects to comply with Chapter 116,

Subchapter I of this title (relating to Electric Generating Facility Permits).

(12) Electric generating facility (EGF)–A facility that

generates electric energy for compensation and is owned or operated

by a person in this state, including a municipal corporation, electric

cooperative, or river authority.

(13) El Paso Region–All of El Paso County, Ciudad

Juarez, Mexico, and Sunland Park, New Mexico.

(14) Grandfathered EGF–A facility that is not subject to

the requirement to obtain a permit under TCAA, §382.0518(g), and

that generates electric energy for compensation and is owned or

operated by a person in this state, including a municipal corporation,

electric cooperative, or river authority.

(15) Heat input–The heat derived from the combustion of

any fuel at an EGF. Heat input does not include the heat derived from

reheated combustion air, recirculated flue gas, or exhaust from other

sources.

(16) NOx allowance–An authorization to emit is valid only

for the purposes of meeting the requirements of this division and

Chapter 116, Subchapter I of this title.

(17) Person–For the purpose of initial issuance of permits

under Chapter 116, Subchapter I of this title, and for the issuance

of allowances under this division, a person includes an individual, a

partnership of two or more persons having a joint or common interest,

a mutual or cooperative association, and a corporation, but does not

include an electric cooperative.

(18) SO2 allowance–An authorization to emit SO2 valid

only for the purposes for meeting the requirements of this division

and Chapter 116, Subchapter I of this title.

(19) West Texas Region–All counties not contained in the

East Texas Region or El Paso Region.

§101.331. Applicability.

This division applies only to the following:

(1) electric generating facilities permitted under Chapter

116, Subchapter I of this title (relating to Electric Generating Facility

Permits); and

(2) brokers.

§101.332. General Provisions.

(a) Allowances are valid only for the purposes of meeting

the requirements of this division and for meeting the requirements of

Chapter 116, Subchapter I of this title (relating to Electric Generating

Facility Permits), and cannot be used to meet or exceed the limitations

of any annual emission limitation authorized under Chapter 116,

Subchapter B of this title (relating to New Source Review Permits)

or any applicable rule or law.

(b) On June 1 after every control period, a grandfathered or

electing electric generating facility (EGF) shall hold a quantity of

allowances in its compliance account that is equal to or greater than

the total emissions of that air contaminant emitted during the prior

control period. Compliance with the allowance system will begin

with the control period beginning May 1, 2003.

(c) Emission reductions used to satisfy the requirements of

the Emissions Banking and Trading of Allowances (EBTA) program

cannot be used to generate emission reduction credits or discrete

emission reduction credits.

(d) Allowances cannot be used for netting requirements to

avoid the applicability of federal and state new source review (NSR)

requirements.

25 TexReg 148 January 7, 2000 Texas Register
(e) Allowances cannot be used to satisfy offset requirements

for new or modified sources subject to federal nonattainment NSR

requirements.

(f) An allowance does not constitute a security or a property

right.

(g) All allowances will be allocated, transferred, or used as

whole allowances. To determine the number of whole allowances,

the number of allowances will be rounded down for decimals less

than 0.50 and rounded up for decimals of 0.50 or greater.

(h) One compliance account shall be used for multiple EGFs

permitted under Chapter 116, Subchapter I of this title located at the

same property and under common ownership or control.

§101.333. Allocation of Allowances.

Allowances will be allocated according to the requirements of this

section.

(1) Except as provided in paragraphs (2) and (3) of this

section, allowances will be calculated for grandfathered electric

generating facilities (EGF) using the following equation:

Figure: 30 TAC §101.333(1)

(A) In the East Texas Region:

(i) 0.14 pound nitrogen oxides (NOx

) per MMBtu;

and

(ii) 1.38 pounds sulfur dioxide (SO2

) per MMBtu

only for coal-fired grandfathered EGFs.

(B) In the West Texas and El Paso Regions, 0.195

pound per MMBtu.

(2) For electing EGFs, the amount of allowances is equal

to emissions as listed in the 1997 Emissions Scorecard from EPA’s

Acid Rain Program, or if not listed in the 1997 Emissions Scorecard,

by a method approved by the executive director, consistent with the

emission reduction requirements of this division; and in both cases,

shall not exceed any of the following:

(A) any annual emission limitation authorized under

Chapter 116, Subchapter B of this title (relating to New Source Review Permits);

(B) an applicable state or federal requirement.

(3) The commission may invalidate any allowances allocated to an electing EGF that authorize emissions in excess of applicable state or federal requirements.

(4) If emissions of NOx or, if applicable, SO2

, exceed the

amount of allowances for a given control period, allowances for

the next control period will be reduced in an amount equal to the

emissions exceeding the allowances in the compliance account.

(5) Allowances will be allocated:

(A) initially, by:

(i) January 1, 2000, for grandfathered EGFs;

(ii) January 1, 2001, for electing EGFs; and municipal corporations, electric cooperatives, and river authorities that

choose to obtain a permit under Chapter 116, Subchapter I of this

title (relating to Electric Generating Facility Permits) for any grandfathered or electing EGFs previously exempted under §116.910(d) of

this title (relating to Applicability);

(B) subsequently, by May 1 of each year, beginning in

2004.

(C) allowances will be allocated:

(i) initially by commission order for all grandfathered and electing EGFs;

(ii) notwithstanding clause (iii) of this subparagraph, at the beginning of each control period, the commission will

deposit the same amount of allowances into each grandfathered or

electing EGF’s compliance account;

(iii) for electing EGFs, the annual deposit for any

control period may be adjusted to reflect new state or federal

requirements.

(6) Allowances may be deducted from compliance

accounts following the review of trading reports required under

§101.336(b) of this title (relating to Emission Monitoring, Compliance, Demonstration, and Reporting).

(7) The commission shall maintain a registry of the

allowances in each compliance account. For each transfer, the registry

shall include the price paid per allowance. The registry shall not

contain proprietary information.

§101.334. Allowance Deductions.

Allowances will be deducted from a grandfathered or electing electric

generating facility’s (EGF) compliance account for a control period

based upon the following.

(1) The following will have deducted from their compliance accounts allowances equal to the number of tons of air contaminant emitted during the control period as reported in compliance with

§101.336 (relating to Emission Monitoring, Compliance Demonstration, and Reporting.

(A) grandfathered EGFs; and

(B) electing EGFs whose heat input for the control

period is equal to or greater than its heat input for 1997;

(C) electing EGFs whose heat input for the control

period is less than its heat input for 1997 where the reduced utilization

or shutdown has been replaced by another EGF permitted under

Chapter 116, Subchapter I of this title (relating to Electric Generating

Facility Permits).

(2) For electing EGFs whose heat input for the control

period is less than the heat input for 1997 and whose reduced

utilization or shutdown has not been replaced by another EGF,

allowances will be deducted from the compliance account according

to the following equation:

Figure: 30 TAC §101.334(2)

(3) For electing EGFs whose heat input for the control

period is less than the heat input for 1997 and whose reduced

utilization or shutdown has been replaced by another EGF not

permitted under Chapter 116, Subchapter I of this title, allowances

will be deducted from the compliance account according to the

following equation:

Figure: 30 TAC §101.334(3)

§101.335. Allowance Banking and Trading.

(a) Allowances not used for compliance during a control

period may be banked for use in subsequent control periods.

Allowances may only be used for the control period for which they

were allocated or subsequent control periods, and may only be used

within the same region where they were originally allocated.

(b) Allowances may be traded at any time during the control

period.

ADOPTED RULES January 7, 2000 25 TexReg 149
(1) Only authorized account representatives may trade

allowances.

(2) Notification of trades must occur within 30 days after

the trade.

(c) Allowance trades are prohibited prior to May 1, 2003.

(d) Traded allowances held in compliance accounts must have

originated from electric generating facilities in the same region.

(e) Allowances may be held only in compliance accounts for

use by EGFs located in the region in which the allowances were

originally allocated or in broker accounts.

§101.336. Emission Monitoring, Compliance Demonstration, and

Reporting.

(a) Emission monitoring and reporting shall be conducted

in accordance with §116.914 of this title (relating to Emissions

Monitoring and Reporting Requirements).

(b) For each control period, grandfathered or electing electric

generating facilities (EGF), must submit a report to the commission

by June 30 of each year detailing the following:

(1) the amount of emissions of each allocated air contaminant during the preceding control period.

(2) a summary of all final trades for the preceding control

period.

§101.337. El Paso Region.

(a) A grandfathered or electing electric generating facility

(EGF) in the El Paso Region may meet the emissions allowances

by using credits from emissions reductions achieved in the City of

Juarez, United States of Mexico and from EGFs located in Sunland

Park, New Mexico. Emission reductions under this section must meet

the following criteria.

(1) The emission reduction must be:

(A) enforceable by the commission;

(B) permanent, meaning that the emission reduction is

unchanging for the remaining life of the source;

(C) quantifiable, so that the emission reduction can be

measured or estimated with confidence using replicable techniques;

(D) surplus, such that the emission reduction is not

otherwise required of a facility by a state or federal law, regulation,

or agreed order; and

(E) a real reduction in which actual emissions are

reduced.

(2) The emission reduction must be reviewed and approved by the executive director prior to converting the credits into

allowances under this program.

(b) Grandfathered and electing EGFs in the El Paso Region

are exempt from the requirements of this division if either EPA or

the commission determines that reductions of nitrogen oxides in the

El Paso Region that would otherwise be required under this division

would result in an increased ambient ozone level in El Paso County.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 22,

1999.

TRD-9909014

Margaret Hoffman

Director, Environmental Law Division

Texas Natural Resource Conservation Commission

Effective date: January 11, 2000

Proposal publication date: September 10, 1999

For further information, please call: (512) 239-1966

♦♦♦

Chapter 116. CONTROL OF AIR POLLUTION

BY PERMITS FOR NEW CONSTRUCTION OR

MODIFICATION

The Texas Natural Resource Conservation Commission (commission) adopts new §116.16, concerning Voluntary Emission Reduction Permit Definitions; §116.810, concerning Eligibility; §116.811, concerning Voluntary Emission Reduction

Permit Application; §116.812, concerning Project Emission

Reduction Credits; §116.813, concerning Application Review

Schedule; §116.814, concerning General and Special Conditions; §116.816, concerning Deferral of Emission Reductions; §116.820, concerning Modifications; §116.840, concerning Public Participation for Initial Issuance; §116.841, concerning Notice and Comment Hearings for Initial Issuance;

§116.842, concerning Notice of Final Action; §116.850, concerning Voluntary Emission Reduction Permit Application Fee;

§116.860, concerning Voluntary Emission Reduction Permit Renewal; and §116.870, concerning Delegation. These new sections implement those portions of Senate Bill (SB) 766, 76th

Legislature, 1999, that require the commission to create a voluntary emission reduction permit (VERP) program. These new

sections will be placed in a new Subchapter H, concerning Voluntary Emission Reduction Permit.

The commission also adopts new §116.601, concerning Types

of Standard Permits; §116.602, concerning Issuance of Standard Permits; §116.603, concerning Public Participation in

Issuance of Standard Permits; §116.604, concerning Duration and Renewal of Registrations to Use Standard Permits;

§116.605, concerning Standard Permit Amendment and Revocation; §116.606, concerning Delegation; and amendments to

§116.610, concerning Applicability; §116.611, concerning Registration to use a Standard Permit; and §116.614, concerning

Standard Permit Fees. These new sections and amendments

implement those portions of SB 766 that authorize the commission to issue standard permits. The commission also intends

§§116.601-116.605, 116.610, 116.611, and 116.614 to be revisions to the state implementation plan (SIP).

Sections 116.16, 116.601, 116.603, 116.604, 116.605,

116.614, 116.810, 116.811, 116.812, 116.816, 116.840,

116.842, and 116.850 are adopted with changes to the

proposed text as published in the September 10, 1999 issue of

the Texas Register (24 TexReg 7148). The remaining sections

are adopted without changes and will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS

FOR THE ADOPTED RULES CONCERNING VERPS

During the 75th legislative session in 1997, House Bill (HB)

3019 directed the commission to develop a voluntary emissions

reduction plan for the permitting of existing significant sources.

These existing significant sources are commonly known as

grandfathered facilities. A grandfathered facility is one that existed at the time the legislature amended the Texas Clean Air

Act (TCAA) in 1971. These facilities were not required to com25 TexReg 150 January 7, 2000 Texas Register
(4) anticipated state or federal regulations that may require reductions of the air contaminants being deferred; and

(5) the benefit to public health from the reduction of other

specific air contaminants versus the deferral.

§116.840. Public Participation for Initial Issuance.

(a) An applicant for a voluntary emission reduction permit

(VERP) shall publish notice of intent to obtain the permit in

accordance with Chapter 39, Subchapters H and K of this title

(relating to Applicability and General Provisions; and Public Notice

of Air Quality Applications).

(b) Any person who may be affected by emissions from a

grandfathered facility may request the commission to hold a notice

and comment hearing on the VERP application. The public comment

period shall end 30 days after the publication of Notice of Receipt of

Application and Intent to Obtain Permit under §39.418 of this title

(relating to Notice of Receipt of Application and Intent to Obtain

Permit). Any hearing request must be made in writing during the

30-day public comment period.

(c) Any hearing regarding initial issuance of a VERP shall

be conducted under the procedures in §116.841 of this title (relating

to Notice and Comment Hearings for Initial Issuance) and not under

the APA.

(d) The commission’s response to public comments and the

notice of its decision on whether to issue or deny a VERP will be

conducted under the procedures in §116.842 of this title (relating to

Notice of Final Action).

(e) A person affected by a decision to issue or deny a VERP

may seek review, as appropriate, under the appropriate procedure

in Chapter 50 of this title (relating to Action on Applications and

Other Authorizations), and may seek judicial review under TCAA,

§382.032, relating to Appeal of Commission Action.

§116.842. Notice of Final Action.

(a) After the public comment period or the conclusion of any

notice and comment hearing, the commission will send notice by firstclass mail of the final action on the application to any person who

commented during the public comment period or at the hearing, and

to the applicant.

(b) The notice must include the following:

(1) the response to any comments submitted during the

public comment period;

(2) identification of any change in the conditions of the

draft permit and the reasons for the change; and

(3) a statement that any person affected by the decision

of the commission may petition for a rehearing under the appropriate

procedure in Chapter 50 of this title (relating to Action on Applications and Other Authorizations) and may seek judicial review under

TCAA, §382.032, relating to Appeal of Commission Action.

§116.850. Voluntary Emission Reduction Permit Application Fee.

Any person who applies for a voluntary emission reduction permit

(VERP) shall remit a fee.

(1) If the grandfathered facility will use a control method

at least as stringent as those defined in §116.811(3)(A) or (B) of this

title (relating to Voluntary Emission Reduction Permit Application),

the application fee shall be $450.

(2) If the grandfathered facility will defer emission reductions under §116.811(3)(C) of this title, or if the grandfathered facility

will use emission reduction credits under §116.811(3)(D) of this title,

the application fee shall be $1,000.

(3) Only one of the applicable fees required in paragraphs

(1) and (2) of this section shall be remitted with a single VERP

application which proposes to control more than one facility at an

account. If more than one facility is included in a single VERP

application, the applicant shall remit the highest of the applicable

fees.

(4) Notwithstanding paragraph (1) of this section, the

maximum fee for a VERP for a small business, as defined in FCAA,

§507(c), shall be $100, if the grandfathered facility will use a control

method at least as stringent as those defined in §116.811(3)(A) or (B)

of this title.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 22,

1999.

TRD-9909013

Margaret Hoffman

Director, Environmental Law Division

Texas Natural Resource Conservation Commission

Effective date: January 11, 2000

Proposal publication date: September 10, 1999

For further information, please call: (512) 239-1966

♦♦♦

Chapter 116. CONTROL OF AIR POLLUTION

BY PERMITS FOR NEW CONSTRUCTION OR

MODIFICATION

The Texas Natural Resource Conservation Commission

(TNRCC or commission) adopts new §116.18, Electric Generating Facility Permits Definitions; §116.910, Applicability;

§116.911, Electric Generating Facility Permit Application;

§116.912, Electric Generating Facility Permit Application for

Electing Electric Generating Facilities; §116.913, General

and Special Conditions; §116.914, Emissions Monitoring and

Reporting Requirements; §116.916, Permits for Grandfathered

and Electing Electric Generating Facilities in El Paso County;

§116.920, Public Participation for Initial Issuance; §116.921,

Notice and Comment Hearings for Initial Issuance; §116.922,

Notice of Final Action; §116.930, Modifications; and §116.931,

Renewal. Sections 116.18, 116.910 - 116.914, 116.916,

116.920 - 116.922, and 116.931 are adopted with changes

to the proposed text as published in the September 10, 1999

issue of the Texas Register (24 TexReg 7163). Section 116.930

is adopted without changes and will not be republished. The

new sections will be submitted as a proposed revision to the

state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS

FOR THE ADOPTED RULES

Senate Bill 7 (SB 7), 76th Legislature, 1999, amended Texas

Utilities Code (TUC), Title 2, concerning Public Utility Regulatory Act, Subtitle B, concerning Electric Utilities, and created

a new TUC, Chapter 39, concerning Restructuring of Electric

Utility Industry. SB 7 requires the commission to implement the

permitting and allowance requirements of new TUC, §39.264,

concerning Emissions Reductions of "Grandfathered Facilities."

ADOPTED RULES January 7, 2000 25 TexReg 185
Section 39.264 requires electric generating facilities (EGF) that

were existing on January 1, 1999, and that were not subject

to the requirement to obtain a permit under Texas Clean Air

Act (TCAA), §382.0518(g) to obtain a permit from the commission. These facilities are referred to as grandfathered facilities.

A grandfathered facility is one that existed at the time the Legislature amended the TCAA in 1971. These facilities were not

required to comply with (i.e., grandfathered from) the then new

requirement to obtain permits for construction or modifications

of facilities that emit air contaminants.

These new sections are adopted concurrently with amendments

and new sections in 30 TAC Chapter 101, concerning General

Rules. The new Division 2, concerning Emission Banking and

Trading of Allowances, in the new Chapter 101, Subchapter

H, concerning Emissions Banking and Trading, sets out the allowance system to be used to assist grandfathered and electing

EGFs in meeting the emission reduction requirements of TUC,

§39.264. The purpose of the rulemaking in these chapters is to

implement permit and emission control requirements, including

emission banking and trading of allowances (EBTA), for grandfathered and electing EGFs and related permit application and

public notice procedures. The permit application and public notice procedures are the subject of these amendments to Chapter

116. The adopted amendments to Chapter 101 are published

in this issue of the Texas Register.

TUC, §39.264 requires owners or operators of grandfathered

EGFs to apply for a permit to emit nitrogen oxides (NOx

)

and, for coal-fired grandfathered EGFs, sulfur dioxide (SO2

)

and particulate matter (PM) through opacity limitations. These

applications are due on or before September 1, 2000. A

grandfathered EGF that does not obtain a permit may not

operate after May 1, 2003, unless the commission finds good

cause for an extension. It is the intent of TUC, §39.264

that for the 12-month period beginning May 1, 2003, and for

each 12-month period following, annual emissions of NOx from

grandfathered EGFs not exceed 50% of the NOx emissions

reported to the commission for 1997. Furthermore, it is the

intent of the legislation that emissions of SO2 from coal-fired

grandfathered EGFs not exceed 75% of the SO2 emissions

reported to the commission in 1997. The described emission

limitations may be satisfied by using control technology or by

participating in the banking and trading of allowances. In

addition, TUC, §39.264(e) requires electric generating facility

permit (EGFPs) for coal-fired, grandfathered EGFs to contain

appropriate opacity limitations provided by the commission’s

rules in §111.111, of this title, Requirements for Specified

Sources, thus permitting emissions of particulate matter.

Persons, municipal corporations, electric cooperatives, and river

authorities owning permitted EGFs may elect to become subject

to the permitting requirements and emission reductions. A

municipal corporation, electric cooperative, or river authority

may exclude any grandfathered EGF with a nameplate capacity

of 25 megawatts or less from permitting and emission reduction

requirements. TUC, §39.264(d) requires notice of the intent to

exclude these grandfathered EGFs by January 1, 2000.

SECTION BY SECTION DISCUSSION

The new §116.18 contains the following definitions. The definitions of "Allowance," "Coal," "Coal-fired," "Compliance account,"

"Control period," "Electric generating facility," "Electing electric

generating facility," "Grandfathered electric generating facility,"

and "Person" were all revised to cross-reference concurrently

adopted definitions of these terms in 30 TAC §101.330, Definitions. "Nameplate capacity" means the maximum electrical

output (expressed in megawatts) that an EGF can sustain over

a specified period of time when not restricted by seasonal or

other deratings. This definition is consistent with the definition used in the Federal Clean Air Act (FCAA) Amendments of

1990, Acid Rain Program. The commission believes that using

this definition will reduce any confusion for grandfathered EGFs

that are potentially subject to both the Acid Rain Program and

the EBTA program proposed under Chapter 101, Subchapter

H, Division 2. A "Peaking unit" is an EGF that has: 1) an average capacity factor of no more than 10% during the past three

calendar years; and 2) a capacity factor of no more than 20%

in each of those calendar years. "Capacity factor" is either: 1)

the ratio of an EGF’s actual annual electric output (expressed in

megawatt-hours) to the EGF’s nameplate capacity times 8,760

hours; or 2) the ratio of an EGF’s annual heat input (in millions

of British thermal units (MMBtu)) to the EGF’s maximum design

heat input (in MMBtu) times 8,760 hours. Both terms, "Peaking

unit" and "Capacity factor," are consistent with the same terms

in the FCAA Acid Rain Program.

Section 116.910 states that a permit under this Subchapter I

would authorize emissions of NOx for any grandfathered EGF,

and PM through opacity limitations and emissions of SO2 for

coal-fired grandfathered EGFs. Owners or operators of electing

EGFs may opt to obtain allowances under the EBTA in Chapter 101, Division 2. The electing EGF’s existing new source

review (NSR) permit will be altered using the procedures in

§116.116(c). This NSR permit alteration will ensure that the existing NSR permit is changed to cross-reference to the EGFP.

Section 116.910 specifies that the owner or operator who is authorized to act for the owner of a grandfathered or electing EGF

is responsible for complying with Subchapter I. Consistent with

TUC, §39.264(d), a municipal corporation, electric cooperative,

or river authority may exclude any grandfathered EGF with a

nameplate capacity of 25 megawatts or less from Subchapter I.

The municipal corporation, electric cooperative, or river authority must notify the commission by January 1, 2000, of its intent to

exclude those grandfathered EGFs. In response to comments,

the commission has revised §116.910(d) to allow municipal corporations, electric cooperatives, or river authorities to notify the

commission of its intent to obtain a permit after January 1, 2000.

Applications must still be submitted by the statutory deadline

of September 1, 2000. A new §116.910(g) was added to the

adopted rule that excludes an EGF that generates electric energy primarily for internal use, but that during 1997 sold, to

a utility power distribution system, less than one-third of its potential electrical output capacity or less than 219,000 megawatthours. This exclusion eliminates cogeneration facilities that the

commission believes were not intended to be included in this

program. The reference to 219,000 megawatt-hours is added

to exempt small cogenerators who may exceed the one-third

limitation. This is more consistent with the Acid Rain Program

exemption for affected units.

TUC, §39.264 requires grandfathered EGFs to obtain a permit

from the commission that authorizes the emission of NOx and,

for coal-fired EGFs, PM through opacity limitations and SO2

.

Grandfathered EGFs also emit products of combustion such

as carbon monoxide (CO) and volatile organic compounds

(VOC). At a coal-fired grandfathered EGF, the emissions may

include mercury as well. The commission believes that the

TUC, §39.264 authorization was only intended to authorize

NOx and, if applicable, PM through opacity limitations and SO2

.

25 TexReg 186 January 7, 2000 Texas Register
The commission also believes that the intent of TUC, §39.264

was to eliminate the grandfathered status of EGFs. However,

it is unclear how TUC, §39.264 authorizes or requires the

permitting of anything other than NOx and for coal-fired EGFs,

PM through opacity limitations and SO2

. Furthermore, if the

commission were to permit these other air contaminants in an

EGFP, it is unclear what standards should be applied to these air

contaminants. Therefore, the commission will use the emission

control standards of the voluntary emission reduction permit

(VERP) program adopted concurrently in this issue of the Texas

Register under 30 TAC Chapter 116, Subchapter H, Voluntary

Emission Reduction Permits. These other air contaminants

from the EGFs will be reviewed under the requirements of the

VERP program, but would only go through the public notice

process one time.

The commission believes that it is appropriate to rely on the

control methods and health effects requirements of the VERP

program for the other air contaminants. The VERP program

provides control method options that depend on the location of

a grandfathered facility. The VERP program also describes the

suggested methods for a health effects review for grandfathered

facilities. The reliance on the VERP control methods and health

effects review will provide a consistent basis of review for the

other emissions from all grandfathered EGFs. The commission

does not think it is appropriate to merely include other emissions

in a grandfathered EGF’s permit without a review of control

methods and, if necessary, impacts. This is consistent with the

commission’s longstanding policy to not treat certain facilities as

being "permitted" simply because the facilities are consolidated

into an existing permit. For example, a facility that was originally

authorized by an exemption will continue to be authorized under

the exemption even though the exemption is consolidated with

an NSR permit during an amendment or at renewal. The

final rules do not require applicants to permit these other air

contaminants from EGFs.

Many power plants may have other grandfathered support

facilities such as fuel storage tanks or coal handling facilities

that are not EGFs. Because TUC, §39.264 addresses only

those facilities which generate electricity for compensation,

these support facilities are not explicitly required to obtain a

permit under TUC, §39.264. To encourage the permitting of

grandfathered support facilities, these facilities could apply for

a VERP which would be consolidated with the EGFP. This

would enable all the grandfathered facilities and EGFs at a

site to go through a consolidated permitting process. Thus,

all grandfathered facilities and EGFs would only go through the

public notice process one time.

To address electing EGFs, §116.910(b) provides that the existing NSR permit be altered using the procedures in §116.116(c),

Alterations. The altered NSR permit would continue to authorize emissions of all air contaminants, and would include a reference to the EGFP. The EGFP will contain the general and

special conditions for electing EGFs. The unchanged, existing

NSR permit conditions would not be subject to public notice

since that permit will only be altered to reflect the existence of

the EGFP.

The new §116.911 contains application procedures for grandfathered and electing EGFs to obtain an EGFP. As specified by

TUC, §39.264(e), the new §116.911 requires owners or operators of grandfathered and electing EGFs to apply for a permit

on or before September 1, 2000. The section also contains

information concerning general content of the permit application for both grandfathered and electing EGFs. Emissions of

air contaminants other than NOx or, if applicable, PM through

opacity limitations and SO2 from an electing EGF already authorized by Chapter 116, are not required to be authorized under

this subchapter. An EGFP will include provisions for measurement of emissions, monitoring, and reporting to calculate actual

emissions over a control period. Although control technology is

not explicitly required under TUC, §39.264, grandfathered or

electing EGFs may propose the use of controls in their initial

applications. The new provisions in §116.911(a)(2) require new

controls to comply with specified provisions in §116.617, Standard Permits for Pollution Control Projects. The commission

believes that relying on these existing procedures for the installation of controls will provide an efficient review process. The

new §116.911(a)(3) specifies that, in cases where there are

increased emissions from the addition of new controls, air dispersion modeling and/or ambient monitoring may be required

to determine off-property impacts. TUC, §39.264(e) requires

coal-fired EGFs to comply with the opacity limits specified in

commission rules. Applicants must submit an application for an

EGFP under the seal of a Texas licensed professional engineer,

consistent with §116.110(e), concerning Applicability.

In response to comments, the commission deleted the references to federal rules and regulations in §116.911 and

§116.913. This deletion will simplify the application process

for EGFPs. However, EGFs must comply with any applicable federal requirements, including, but not limited to, nonattainment review, Prevention of Significant Deterioration (PSD)

review, New Source Performance Standards (NSPS), National

Emission Standards for Hazardous Air Pollutants (NESHAPS),

and NESHAPS for Source Categories. EGFs that are affected

sources under FCAA, §112(g), concerning Modifications, must

comply with those requirements. The issuance of an EGFP

does not modify or limit the applicability of these federal programs. If, during the review of an application for an EGFP the

commission determines that the EGF is not in compliance with

any applicable state or federal standards, the commission will

initiate the appropriate enforcement action which may include a

requirement to obtain an NSR permit or the applicable federal

permit.

EGFs that are currently authorized under Chapter 116 may elect

to participate in the EBTA under Chapter 101, Subchapter H,

Division 2. The proposed §116.912 contained application requirements for electing EGFs that were in addition to those

contained in the proposed §116.911. Those requirements are

now in §116.911(b). Since an existing NSR permit may authorize multiple facilities, the permit application submitted under

Subchapter I should identify which EGFs are to be included in

the EGFP. The application must include documentation of the

emissions from the 1997 Emissions Scorecard from the United

States Environmental Protection Agency (EPA) Acid Rain Program, or if that information is not available, the actual emissions

from that electing EGF for calendar year 1997. Applications

must contain documentation of actual emissions as well as fuel

consumption, fuel heating values, and heat input in MMBtu for

calendar year 1997. This information will be used to calculate allowances for these EGFs and provide the data needed

to meet the requirements of TUC, §39.264(i)(3), which restricts

the banking and trading of allowances that result from reduced

utilization and shutdown.

The new §116.912 was renamed "Electing Electric Generating

Facilities." The proposed §116.912 contained the application

ADOPTED RULES January 7, 2000 25 TexReg 187
content requirements for electing EGFs. These requirements

were moved to the new §116.911(b). Section 116.912 now

contains the requirements for opting in and out of the permitting

program. An electing EGF may opt out of the requirements of

this subchapter under certain conditions. The electing EGF

must notify the commission of its intent to opt out prior to the

beginning of the next control period and may not opt out during

a control period. This notification requirement would prevent an

EGF from opting out in order to avoid being out of compliance

with the requirement to not exceed its allowances. The decision

to opt out will become effective at the beginning of the control

period following notification to the commission. All allowances

for the electing EGF will be voided by the commission and

may not be banked for subsequent use. Since the EGF would

no longer be subject to the restrictions of the EBTA, it would

be inappropriate to use those allowances at other EGFs, and

no allowances will be allocated for subsequent control periods.

Once an EGF has opted out, the EGF may not participate in the

EBTA at any future date. Since TUC, §39.264 states that EGFs

must elect to participate prior to September 1, 2000, there is

not a subsequent opportunity for those EGFs to reelect. The

commission believes that a one-time election and a one-time opt

out provide sufficient flexibility without undermining the program.

The owner or operator shall request an alteration to the electing

facility’s NSR permit to remove the conditions pertaining to the

EGFP. This alteration would restore the NSR permit to its prior

status.

The new §116.913 contains general conditions applicable to every EGFP unless specified differently in the permit, and authorizes the commission to include special conditions in the permit.

An EGFP would authorize NOx emissions from EGFs, and from

coal-fired EGFs, SO2 emissions and PM through opacity limitations. The EGF must comply with the EBTA in Chapter 101,

Subchapter H, Division 2. In response to comments, former

§116.913(a)(1)(C), concerning emissions of air contaminants

other than NOx

, SO2, and PM through opacity limitations from

grandfathered EGFs, as defined in §116.10, concerning General Definitions, was reorganized and its provisions are now in

§116.913(a)(2) and (3). An EGFP may permit emissions of all

other air contaminants from grandfathered EGFs, provided the

requirements of Chapter 116, Subchapter H are met. VERPs

for grandfathered facilities as defined in §116.10 at sites with

grandfathered or electing EGFs may be consolidated with an

EGFP. The provisions for the EBTA require EGFs to maintain

allowances in a compliance account. The EBTA in Chapter

101 contains all provisions for managing allowances. For emissions of NOx and, where applicable, SO2

, the EGF shall hold

in its account, on June 1 after every control period, a quantity

of allowances equal to or greater than the amount of that air

contaminant emitted since May 1 of the previous year. Holders

of EGFPs shall comply with this requirement beginning May 1,

2004. Beginning May 1, 2004, holders of EGFPs must report

annual actual emissions of NOx and, if applicable, SO2

, for the

previous control period. This emissions report must be submitted by June 30 of each year, and will be used to determine

compliance with the requirement that the EGF hold allowances

equal to or greater than the emissions over a given control period. The adopted section implements TUC, §39.264(e) and

requires coal-fired EGFs to comply with the opacity limits specified in commission rules.

The new §116.914 specifies monitoring and reporting requirements for EGFPs, and the adoption was reorganized for clarity

in response to comments. The commission is required by TUC,

§39.264(k) to provide methods for use in determining compliance with permits and methods for monitoring and reporting

actual emissions of NOx and, if applicable, SO2

. Title 40 Code

of Federal Regulations (CFR) Part 75, concerning Continuous

Emission Monitoring Under the Acid Rain Program (Acid Rain

Program), contains monitoring requirements for SO2 for affected

units under that program. Since the acid rain program already

requires extensive monitoring, the adopted rule authorizes the

use of that monitoring for EGFs that are subject to the acid rain

program for compliance with Subchapter I. EGFs not subject to

the Acid Rain Program would have three choices in monitoring.

The EGF may choose to meet either Part 75 monitoring requirements, or the requirements of Title 40 CFR Part 60, or the EGF

may provide an alternative monitoring plan that would be incorporated into the permit conditions. Part 60 requirements are

adopted as an alternative to Part 75 in order to be consistent

with current NSR practices for facilities not required to comply

with Part 75. Since Part 60 monitoring may be less accurate

than Part 75 monitoring, the adopted rule requires Part 60 monitored data to have a relative accuracy of greater than 10% (i.e.,

measured values within 90-100% of the correct value). To account for this inaccuracy, the monitored value must be multiplied

by a factor of 1.1. This factor has been included to account for

the inequity between the monitoring accuracy of Parts 75 and

60. The commission believes that this factor, proposed in the

Ozone Transport Commission’s (OTC) Model Rule, is appropriate for the EBTA as well, based on the similarity of the OTC

requirements and the goals of TUC, §39.264. The OTC Model

Rule implements a NOx emission budget program to reduce ambient ozone concentrations. Although Texas is not required to

participate in the OTC budget program, the commission believes that it is appropriate to model this budget rule after the

OTC model rule. Additionally, EGFs with a heat input of less

than 100 MMBtu/hour could use Appendix E of 40 CFR Part 75

to estimate NOx emissions. Appendix E relies on stack testing

of the facility to develop a relationship between the emission

rate and heat input. The commission believes that it is appropriate to structure the monitoring requirements of Subchapter

I on these existing requirements because many EGFs are currently using Part 75 and Part 60 monitoring methods. Data

collected from these monitoring requirements would be used to

calculate annual emissions that are reported to the commission

for the purpose of demonstrating compliance with allowances.

The new §116.914 also specifies that data collected from the

monitoring of EGFs shall be detailed in an annual report as

required under §116.913(a)(7). The commission will develop

a form, AR-1, specifying the requirements of the report, which

would be due on June 30 of each year.

The new §116.916, concerning Permits for Electric Generating

Facilities in El Paso County, was renamed to "Permits for Grandfathered and Electing Electric Generating Facilities in El Paso

County." Consistent with TUC, §39.264(q), §116.916 would exempt EGFs in El Paso County from NOx allowance requirements

if the commission or EPA determines that reductions in NOx

emissions would lead to increased ambient levels of ozone.

Currently, NOx reductions are not required for facilities in the

El Paso nonattainment area because EPA has granted a waiver

under FCAA, §182(f). Under this waiver, NOx reductions are

not required if the attainment demonstration for compliance with

the ozone National Ambient Air Quality Standard (NAAQS) can

be made without a NOx control strategy. The existence of this

waiver is not consistent with the provisions of TUC, §39.264(q)

because it has not been demonstrated, under the §182(f) waiver

25 TexReg 188 January 7, 2000 Texas Register
or otherwise, that NOx reductions would increase ambient ozone

in El Paso County. These EGFs would still be required to obtain

a permit under 30 TAC Chapter 116, Subchapter I regardless

of the determination that NOx reductions are counterproductive

in controlling ambient ozone levels in the El Paso Region. The

commission believes that this requirement is appropriate, since

TUC, §39.264(e) provides that EGFs without a permit may not

operate after May 1, 2003, and TUC, §39.264(q) refers only

to reduction requirements, not permitting requirements. Regardless of this determination, grandfathered EGFs in El Paso

County would still be required to obtain a permit under Subchapter I.

The new §116.920 would require that applicants for initial issuance of an EGFP publish notice of intent to obtain a permit

in accordance with 30 TAC Chapter 39, Subchapter K, concerning Public Notice of Air Quality Applications. Subchapter K implements the new requirements of TCAA, §382.056,

as amended by the 76th Legislature by House Bill (HB) 801,

an act relating to Public Participation in Certain Environmental

Permitting Procedures of the TNRCC. TUC, §39.264 provides

that public participation for initial issuance of an EGFP will be

done in the manner of TCAA, §382.0561, concerning Federal

Operating Permit; Hearing; and TCAA, §382.0562, concerning

Notice of Decision. These sections allow for notice and comment hearings instead of contested case hearings under Texas

Government Code, Chapter 2001, and require the commission

to send notice of final action to persons who comment during

the comment period or during a hearing. The adopted requirements of §116.920, 116.921, and 116.922 are based on the

sections in 30 TAC Chapter 122, concerning Federal Operating

Permits, that implement the requirements of TCAA, §382.0561

and §382.0562. Section 116.920 provides that any person who

may be affected by emissions from the EGF may request a notice and comment hearing on an EGFP application within 30

days after the publication of Notice of Receipt of Application

and Intent to Obtain Permit under §39.418, concerning Notice

of Receipt of Application and Intent to Obtain Permit. Grandfathered support facilities that elect to obtain a VERP and have

it consolidated with an EGFP may publish a combined notice.

Electing EGFs that are included in an EGFP are only included

for the purpose of authorizing NOx emissions, and if applicable, PM through opacity limitations and SO2

. The conditions

of the electing EGF’s existing NSR permit would be altered to

cross-reference the EGFP. Since the rule was revised to require

alterations to the electing EGF’s existing NSR permit, the provision in §116.920(c), concerning public notice for emissions of air

contaminants other than NOx

, or if applicable, SO2, was deleted.

The existing NSR permit conditions would not be subject to public notice. Any conditions in the EGFP concerning the electing

EGFs would be subject to public notice. Persons affected by a

decision to issue or deny an EGFP will be entitled to petition for

a rehearing under the appropriate procedure in Chapter 50, concerning Action on Applications and Other Authorizations, and

may seek judicial review under TCAA, §382.032, concerning

Appeal of Commission Action. The commission made clerical

changes to §116.920 to include references to grandfathered and

electing EGFs and renumbered that section, since §116.920(c)

was deleted. Section 116.920(g), now §116.920(f), was revised

to clarify that a person affected by a decision of the commission to issue or deny an EGFP may seek judicial review. This

change makes this subsection consistent with the language in

§116.922(b)(3).

The commission made clerical revisions to §116.921 to add the

terms "grandfathered" and "electing EGFs" as well as to delete

references to draft permits and refer instead to draft EGFPs.

The new §116.921 contains the hearing requirements for the

initial issuance of EGFPs. The rule allows the commission to

decide whether to hold a hearing based on the reasonableness

of a request. The commission is not required to hold a hearing

if the basis of the request by a person who may be affected by

emissions from the grandfathered or electing EGF is determined

to be unreasonable. If a hearing is requested by a person who

may be affected by emissions from the grandfathered or electing

EGF, and that request is reasonable, the commission will hold a

hearing. The section requires that notice of hearing on a draft

EGFP be published in the public notice section of one issue

of a newspaper of general circulation in the municipality or the

nearest municipality where the EGF is located. The notice must

be published at least 30 days prior to a hearing. The notice is

published at the applicant’s expense and the rule specifies the

content of the notice. The rule provides the procedures for

the submittal of comments at a hearing and specifically states

that the period for submitting written comments extends to the

close of the hearing and may be extended beyond the close of

the hearing. Any person, including the applicant, may submit

comments on whether the draft EGFP contains inappropriate

conditions or whether the preliminary decision to issue or deny

the EGFP is inappropriate. Commenters shall raise all issues

and submit all comments supporting their position by the end

of the public comment period. This requirement will assist

the commission in developing its response to comments as

required by new §116.922. To ensure a complete record of

the comments, the rule prohibits the incorporation by reference

of supporting materials for comments unless the materials meet

the criteria in §116.921(g). The commission is required to keep

a record of all comments submitted or raised at a hearing and

to have an audio recording or written transcript of the hearing,

and the record is available to the public. Draft EGFPs may be

revised based on comments pertaining to whether the permit

provides for compliance with the requirements for an EGFP.

The new §116.922 was revised to include a reference to the

draft EGFP. The new §116.922 requires the commission to

individually notify persons who commented, either during the

public comment period or at a permit hearing, of the final action

of the commission. The notice must be sent by first-class mail to

the commenters and to the applicant. The notice must include

the response to comments, the identification of any changes

in the permit, and a statement that any person affected by the

decision of the commission may petition for rehearing under

the appropriate procedure in Chapter 50, concerning Action on

Applications and Other Authorizations, and may seek judicial

review under TCAA, §382.032.

TUC, §39.264 does not provide procedures for the modification

of an EGFP. The commission believes that the requirements

of the TCAA concerning modifications of existing facilities still

apply. Therefore, the new §116.930 requires that any modifications to any facility in an EGFP are subject to the permitting

requirements of the TCAA and the existing modification requirements in 30 TAC Chapter 116, Subchapter B.

Consistent with TUC, §39.264(r), the new §116.931 requires

EGFPs to be renewed under the requirements of 30 TAC

Chapter 116, Subchapter D, concerning Permit Renewals. The

commission made a clerical revision to this section to delete the

abbreviation of EGFP.

ADOPTED RULES January 7, 2000 25 TexReg 189
FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the rulemaking in light of the

regulatory analysis requirements of Texas Government Code,

§2001.0225, and has determined that the rulemaking meets

the definition of a "major environmental rule" as defined in that

statute. "Major environmental rule" means a rule the specific

intent of which is to protect the environment or reduce risks

to human health from environmental exposure, and that may

adversely affect in a material way the economy, a sector of

the economy, productivity, competition, jobs, the environment,

or the public health and safety of the state or a sector

of the state. The adopted amendments to Chapter 116

are intended to protect the environment or reduce risks to

human health from environmental exposure and may have

adverse effects on grandfathered and electing EGFs which

could be considered a sector of the economy. However, the

analysis required by §2001.0225(c) does not apply, because the

adopted amendments do not meet any of the four applicability

requirements of a major environmental rule. The new sections

do not exceed a standard set by federal law, exceed an

express requirement of state law, or exceed a requirement of a

delegation agreement, and they are not adopted solely under

the general powers of the agency. The amendments to Chapter

116 are adopted specifically to implement TUC, §39.264. TUC,

§39.264 requires grandfathered EGFs apply for a permit by

September 1, 2000, and obtain a permit by May 1, 2003, or

cease operating, absent a showing of good cause to continue

operating. The adopted amendments allow the permitting of all

other air contaminants for grandfathered EGFs using the VERP

process. Support facilities may be permitted under a VERP

which may be consolidated with an EGFP. There is no federal

law or delegation agreement with a federal agency that requires

the permitting of grandfathered EGFs.

TAKINGS IMPACT ASSESSMENT

The commission has completed a takings impact assessment

for the adopted rules. The following is a summary of that assessment. These new sections implement the requirements of

TUC, §39.264. This section requires owners or operators of

grandfathered EGFs to apply for a permit on or before September 1, 2000, and obtain a permit or cease operation by May 1,

2003. It is the intent of §39.264 that for the 12-month period

beginning May 1, 2003, and for each 12-month period following,

annual emissions of NOx from grandfathered EGFs not exceed

50% of the NOx emissions reported to the commission for 1997.

Furthermore, it is the intent of the legislation that emissions of

SO2 from coal-fired EGFs not exceed 75% of the SO2 emissions

reported to the commission in 1997. NOx and SO2 allowances

will be allocated to EGFs by January 1, 2000. To assist EGFs in

meeting the reduction requirements, a banking and trading program is adopted concurrently in Chapter 101. Although EGFs

are required to make specific emission reductions, these facilities have alternatives available under the banking program that

may allow the EGF to avoid installing add-on controls. Further,

allowances can be transferred under the banking program so

that EGFs have opportunities to buy and sell allowances in order

to respond to business needs. The new sections do not affect

private property in a manner that restricts or limits an owner’s

right to the property that would otherwise exist in the absence of

the governmental action. Consequently, this adoption does not

meet the definition of a takings under Texas Government Code,

§2007.002(5). The reductions obtained from the issuance of

EGFPs will assist in the efforts of the commission to attain the

NAAQS. This action is taken in response to a real and substantial threat to public health and safety and significantly advances

the health and safety purpose and imposes no greater burden

than is necessary to achieve the health and safety purpose.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission has determined that this rulemaking relates

to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources

Code, §§33.201 et seq.), and the commission’s rules in 30

TAC Chapter 281, Subchapter B, relating to Consistency with

Texas Coastal Management Program. As required by 31 TAC

§505.11(b)(2) and 30 TAC §281.45(a)(3), relating to actions and

rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and

policies of the CMP. The commission has reviewed this action

for consistency with the CMP goals and policies in accordance

with the regulations of the Coastal Coordination Council. For the

new sections related to the authorization of EGFPs, the commission has determined that the rules are consistent with the

applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural

resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas.

This adoption is intended to reduce overall emissions of NOx

and, if applicable, SO2 from grandfathered EGFs. This action is

consistent with 40 CFR because it does not authorize an emission rate in excess of that specified by federal requirements.

PUBLIC HEARING AND COMMENTERS

The commission conducted public hearings concerning this

adoption in El Paso and Lubbock on October 1, 1999, in Austin

on October 4, in Irving on October 5, in Houston on October 7,

and in Beaumont on October 7.

The following submitted written comments or provided testimony

during the public comment period which closed on October

11, 1999: EPA-Acid Rain Division (EPA-ARD); EPA-Clean Air

Markets Division (EPA-CAMD); EPA-Air Permits Division (EPAAPD); EPA-Air Planning Section (EPA-APS); The University of

Texas System, Office of General Counsel (UT); Enron, Central and South West Services, Inc. (CSW); TXU Business Services (TXU); Brazos Electric Power Cooperative, Inc. (Brazos);

Baker & Botts, L.L.P.-Texas Industry Project (Baker & Botts);

Clark & Seay, L.L.C. (Clark & Seay); Southwestern Public Service Company (SPS); Entergy Gulf States, Inc./Entergy Texas

(Entergy); El Paso Electric Company (EPE); Lloyd, Gosselink,

Blevins, Rochelle, Baldwin & Townsend, P.C.-City of Garland

(Lloyd Gosselink); League of Women Voters of Texas (LWV-TX);

The Center for Energy and Economic Development (CEED); Association of Electric Companies of Texas, Inc. (AECT); Reliant

Energy (Reliant); Entergy Services Inc. (Entergy Services); Environmental Defense Fund (EDF); City of Austin/Austin Energy

(AE); Sustainable Energy and Economic Development Coalition (SEED); Public Citizen, Texas Clean Water Action, Texas

Communities Project (PC); City Public Service of San Antonio

(CPS); Bracewell & Patterson (B&P); Lubbock Power & Light

& Water (LP&L); Clark, Thomas & Winters (CT&W); Central &

South West, City of Austin, City Public Service, El Paso Electric,

Entergy, Reliant Energy, Southwestern Public Service, and TXU

(Group A); (Group A); Mothers for Clean Air (MCA); Neighbors

for Neighbors (NFN); and 17 individuals.

25 TexReg 190 January 7, 2000 Texas Register
ANALYSIS OF TESTIMONY

One individual commented that the commission should exercise

its authority to require significant reductions at power plants in

East Texas, with another individual adding that the reductions

should be permanent. Three individuals stated that the commission should enforce reduced emissions from grandfathered

electric generating facilities, and two more individuals added

that the commission should be as strict as possible in that enforcement.

While this adoption addresses grandfathered EGFs only, the

commission is developing rules that will apply NOx restrictions

on all EGFs in the East Texas Region. The specific level

of emissions required from these facilities will be determined

on computer analysis that indicates what reductions should

be required to assist the affected nonattainment areas in

meeting the NAAQS. The net reductions required under this

adoption are permanent. The commission will exercise its

full enforcement power as authorized by statute, rule, or

as governed by enforcement policy. This adoption requires

mandatory permitting for emissions of NOx and, if applicable

SO2 and PM through the commission’s opacity standards, the

rules provide options for the permitting of other air contaminants

from grandfathered EGFs.

Four individuals stated that the commission should seek improvements that address SO2

, particularly to improve visibility in

Big Bend. Another individual added that the commission must

require a larger NOx and SO2 reduction to reduce acid rain and

ozone in Texas nonattainment areas.

In cooperation with EPA and the National Park Service, the

commission is analyzing the nature and location of required

reductions to address reduced visibility in Big Bend National

Park. This analysis is incomplete and therefore, the commission

believes that requiring reductions specifically to the Big Bend

area prior to the completion of this analysis is premature.

The authority granted to the commission under TUC, §39.264

and other existing authority allows the commission to seek

additional reductions in SO2 as needed. As stated previously,

the commission is addressing additional NOx reductions that

may be required to assist in the attainment of the NAAQS in

a separate rulemaking. There are no areas in Texas that are

nonattainment for SO2

, and the commission is not aware of any

areas that are adversely affected by acid rain.

One individual stated that the commission should not allow a

cap and trade or banking system because it avoids environmental justice issues and perpetuates emissions in low-income

areas. The same individual suggested that the exclusion for

individual units to be regulated under TUC, §39.264 be lowered to ten megawatts from 25 megawatts. This individual also

stated that the commission estimate of cost of compliance with

the requirements of the adoption is low, and it appears that the

commission is allowing low-grade technology to be applied to

the regulated units.

The trading and banking provisions of this adoption are required

elements of the reduction program under TUC, §39.264. SB 7

provides that total annual emissions of NOx from grandfathered

EGFs will not exceed 50% of the NOx emissions in 1997 as reported to the commission and that for coal-fired grandfathered

EGFs, the total annual emissions of SO2 will not exceed 75%

of the emissions during 1997, as reported to the commission.

SB 7 also provides that the trades of allowances will only occur

within the same region, either East Texas, West Texas, or El

Paso. The effect of this will be an overall 50% reduction in NOx

and a 25% reduction in SO2 within the region. SB 7 does not

require a specific level of reduction at any individual grandfathered EGF. The exemption level for individual generating units

of 25 megawatts is specified in TUC, §39.264(d). As discussed

elsewhere in the adoption preamble, the commission has also

excluded EGFs that generate power primarily for internal use,

but that during 1997 sold one-third of their generated power

or less than 219,000 megawatt-hours to the utility power distribution system. The commission believes that excluding these

EGFs is consistent with SB 7 and will not negatively affect the

overall emission reductions required by the program. Lowering

the exemption to ten megawatts will require small generators to

participate in the EBTA and permitting program and will achieve

little environmental benefit in relation to the cost of compliance

with the program. The commission has based its estimate of

the cost of applying control technology to attain the 0.14 pound

per MMBtu on the February 1999 joint Public Utility Commission

of Texas (PUCT) and TNRCC report, Electric Restructuring and

Air Quality: A Preliminary Analysis of Reductions and Costs of

Nitrogen Oxides Controls from Electric Utility Boilers in Texas.

The estimate does not limit the amount EGFs must spend to

meet the EBTA and accounts for technology of necessary sophistication to meet the requirements of this adoption.

The Honorable Lon Burnam, State Representative, District 90,

commented concerning the implementation of SB 7 and its

impact on consumers from an economic perspective. Mr.

Burnam expressed his concerns that the commission implement

the provisions of SB 7 free from the influence of lobbyists. Mr.

Burnam urged the commission to consider public health in the

process of implementing SB 7.

The provisions of SB 7 concerning deregulation of the electric industry will be implemented by the PUCT. The commission

conducted six hearings in order to seek the public comment of

citizens, the regulated community, and environmental groups.

The hearings were conducted in El Paso, Lubbock, Austin, Irving, Houston, and Beaumont. Prior to proposal, the commission

held a stakeholder meeting to seek input from interested persons. Notice of this meeting was provided on the commission’s

web page. In addition, pre-proposal drafts of the rules were

posted on the commissions’s web page with a request for comments. The commission believes that the adopted rules are

consistent with SB 7 and remains committed to implement the

program in a fair and impartial manner. Since EGFs are being

permitted under the requirements of TUC, §39.264, which does

not require a health effects review, no review is included in this

adoption. The commission believes that this program will reduce ambient levels of NOx and SO2 and improve the overall air

quality of the state. These reductions will assist the commission

in its efforts to attain the health-based NAAQS.

Clark & Seay and MCA commented that all power plants that

are in or near an area with unsafe air should be required to meet

the 0.14 pounds/MMBtu standard used in federal laws and to

the level to which all grandfathered plants will be required to

be cleaned up. In addition, LWV-TX commented that the rules

in general be expanded to require all power plants that are in

areas with unsafe air or that contribute to those nonattainment

areas meet the same standard.

This adoption implements the requirements of TUC, §39.264

and application of this statute is limited to grandfathered EGFs

and those EGFs that elect to participate in the permitting and

trading program. The intent of SB 7 is not to achieve attainment

ADOPTED RULES January 7, 2000 25 TexReg 191
with the NAAQS, but to permit and reduce emissions from

grandfathered EGFs. While the implementation of SB 7 will

provide emission reductions in areas near grandfathered EGFs,

the commission recognizes that it will likely be necessary to

adopt rules that will require air pollution control in attainment

areas as well as additional rules for nonattainment areas.

These controls would not only apply to emissions of NOx from

grandfathered EGFs, but permitted EGFs and other sources

of NOx as well. Further, specific emission rates will be

established that have been determined necessary to meet air

quality standards. Rules implementing these additional controls

are scheduled for proposal in late 1999 or early 2000. The

commission is not aware of any federal standards that require

EGFs to meet a NOx emission restriction of 0.14 pounds/MMBtu.

EDF commented that TUC, §39.264(n)(1) includes two specific

penalties for facilities that exceed their allowances. The

commenter noted that the proposed rules did not include any

administrative penalties, and recommended that they be added

at a level sufficient to deter noncompliance. EDF recommended

three times the current market value of allowances.

The commission does not typically address the amount of administrative penalties in specific rules. Rather, penalty amounts

are established in accordance with the commission’s penalty

policy. All enforcement cases not referred to the Office of the

Attorney General go through staff preparation of an administrative penalty recommendation in accordance with the commission’s penalty policy. Staff obtains an agreement or litigates to

obtain an order against the respondent that requires the payment of penalties. The commission determines the amount of

the penalty in accordance with the commission’s enforcement

rules and penalty guidance. The statutory language requires

"enforcing an administrative penalty" and not "assessing" an

administrative penalty.

Reliant requested that the published list of grandfathered EGFs

be revised by deleting the Cedar Bayou Units 1 and 2 (Account

Number CI-0012-D) because the units are no longer grandfathered and are permitted under Permit Number 1532. In addition, Reliant provided heat input information for facilities that

were missing from the proposed list. CPS commented that V.H.

Unit 1 should be corrected from 2,946,936 MMBtu to 2,949,512

MMBtu, as was submitted to EPA in the Acid Rain Database.

The commission will make these corrections to the list entitled "Nitrogen Oxide and Sulfur Dioxide Allowances for Grandfathered Electric Generating Facilities."

EPE commented that the language in TUC, §39.102(c) and

§39.264(i) illustrate EPE’s exemption from Chapter 39 and

EPE’s ability to elect to designate a facility to become subject

to §39.264 and they noted that EPE is a "person" under PURA.

The commission agrees that EPE is a "person" under the

TUC. The commission has not revised the rule to exempt EPE

from the program requirements. TUC, Subchapter C, Retail

Competition, §39.102, concerns retail customer choice, and

exempts from TUC Chapter 39, any electric utility that has a

system-wide freeze for residential and commercial customers

that is in effect from September 1, 1997 and extends beyond

December 31, 2001, that has been found by a regulatory

authority to be in the public interest. Subchapter C also contains

§39.264, which requires any EGF that existed on January 1,

1999, that is not subject to the requirement to obtain a permit

under TCAA, §382.0518(g), to apply for and obtain a permit

from the commission.

Section 39.264 was added to SB 7 during the final weeks

of the 76th Legislative Session. Its very specific intent is

to require grandfathered EGFs to obtain a permit from the

commission and to obtain reductions of NOx and SO2 in the

regions as defined by the bill. TUC, §39.264 contains several

specific references to the El Paso area that make it clear

that the Legislature intended EGFs in that area to be subject

to the permitting and allowance program. TUC, §39.264(g)

requires the commission to develop rules that define the "El

Paso Region." TUC, §39.264(h) specifies an emission rate for

the El Paso Region. TUC, §39.264(p) specifically requires the

commission to develop rules to allow EGFs in the El Paso

Region to meet emissions allowances by using credits from

reductions made in Ciudad Juarez, United States of Mexico.

Finally, TUC, §39.264(q) allows the commission to exempt

EGFs in the El Paso Region if the commission determines

that reductions in NOx would result in an increased amount of

ambient ozone levels in El Paso County.

The Code Construction Act, §311.021, Texas Government

Code, provides that "In enacting a statute, it is presumed

that: (1) compliance with the constitutions of this state and

the United States is intended; (2) the entire statute is intended

to be effective; (3) a just and reasonable result is intended;

(4) a result feasible of execution is intended; and (5) public

interest is favored over any private interest." If TUC, §39.102

were read to exclude EGFs in the El Paso Region from

the provisions of Chapter 39, the specific provisions of TUC,

§39.264, concerning the El Paso Region, would be rendered

ineffective. As prescribed by the Code Construction Act, the

commission must interpret the provisions of Chapter 39 so

that all sections can be given effect. To do otherwise would

contravene the intent of the Legislature. Thus, the commission

agrees that EPE is exempt from the provisions regarding

customer choice in TUC, Chapter 39. However, if EPE were

exempted from the permitting and EBTA requirements, the

provisions of TUC, §39.264, concerning the El Paso Region,

would be meaningless. The commission agrees that EPE may

use the provisions of §116.912, concerning Electing EGFs.

Lloyd Gosselink commented that the rules do not address the

use of oil as a backup fuel at a gas- fired facility. The commenter

stated that under certain curtailment situations, gas may not be

available, and gas-fired facilities may be required to switch to

oil as a fuel source, and that under these conditions, facilities

should not be penalized for any additional NOx emissions.

The commission believes that a facility has the latitude to use

any fuel as long as actual emissions comply with its allotted

allowances, and the use is authorized by the appropriate NSR

authorization. The commission does not believe it is appropriate

to revise the rules to include an exception to exceed allowances

in the case of a curtailment because SB 7 does not allow for

this exception. If a curtailment occurs, and emissions of NOx

exceed an EGF’s allowances, the commission will rely on its

enforcement policy to determine the appropriate response. Use

of previously unused fuels may constitute a modification and

require an NSR permit. The rules have not been revised in

response to this comment.

LWV-TX commented that the TNRCC should restrict pollution

trading in ways that assure significant reductions in air pollution.

SB 7 requires the commission to allocate allowances to grandfathered EGFs in defined regions of the state. The specific intent

of SB 7 is that total annual emissions of NOx from grandfathered

25 TexReg 192 January 7, 2000 Texas Register
EGFs will not exceed 50% of the NOx emissions in 1997 as reported to the commission and that for coal-fired grandfathered

EGFs, the total annual emissions of SO2 will not exceed 75%

of the emissions during 1997, as reported to the commission.

The adopted rules provide the requirements for both the permitting of these grandfathered EGFs, and an emission banking and

trading program. Both of these programs are critical to the successful reduction of the NOx and SO2 emissions contemplated

by SB 7. The EBTA contains restrictions on trading that will

ensure that the required emission reductions are enforceable.

The commission believes that the required reporting and monitoring, along with the statutorily defined enforcement provisions,

will ensure that the program achieves the reductions intended

by TUC, §39.264. The commission believes that the implementation and enforcement of the adopted rules will ensure that the

reductions mandated by SB 7 occur and that no modification to

the rule is necessary.

CEED commented that the preamble referenced adopting additional requirements for EGFs in nonattainment areas, indicating

further reductions of 88% in Dallas/Fort Worth (DFW) and 90%

in Houston/Galveston (HGA) areas. The commenter stated that

the emissions inventory shows that these point sources only

represent a minor source of NOx emissions, since the majority

of emissions are generated by on-road and off-road mobile and

area sources, and that the inclusion of these statements regarding the further need to reduce emissions from EGFs continues

to focus attention on sources which will not solve nonattainment problems in these areas. CEED also commented that the

proposal preamble statements that EGFs must consider local

impacts of allowance transfers and that "EGFs emit significant

amounts of NOx

, which has been shown to heavily influence

local ozone levels" are comments without any qualifications to

specific EGFs and perpetuate the opinion by some that all EGFs

emit significant levels of emissions. CPS supports the removal

of all references to SIP requirements from the SB 7 regulations. An example is on page 7140 of the proposal preamble,

where it states that "...EGFs must consider local impacts of

allowance transfers...." Furthermore, the preamble states that

"These EGFs (in near-nonattainment areas) emit significant

amounts of NOx which has been shown to heavily influence

local ozone levels." CPS disagrees which this statement. First,

the mandatory SB 7 program was designed to be flexible, and

allow reductions to be made in the most cost-effective manner.

Second, the utility plants in San Antonio, owned by CPS, do not

contribute heavily to local ozone levels, as indicated by previous

modeling performed by Alamo Area Council of Governments under the direction of the TNRCC. Therefore, TNRCC’s concern

that SB 7 allowance trading will jeopardize the regional strategy

is unwarranted, at least for the near-nonattainment area of San

Antonio.

The reductions mandated by SB 7 only apply to grandfathered

EGFs in the defined regions of Texas. These reductions

from grandfathered EGFs will be significant; however, it is

unlikely that the reductions will be sufficient to address the

need to further reduce emissions in both attainment and

nonattainment areas. The commission believes that to achieve

attainment with the NAAQS, it will be necessary to reduce

emissions from all sources, both stationary and mobile, in

both attainment and nonattainment areas. The reductions that

will be achieved under the adopted rules will be significant

towards reaching attainment. In addition, the commission

believes that NOx emissions from EGFs are not minor, but

significantly contribute to ground-level ozone formation. The

preamble comments regarding the potential impacts of trading

on near-nonattainment areas were included to recognize that

emissions in near- nonattainment areas may have a negative

impact on that areas ability to remain in attainment. Emission

inventory information indicates that NOx emissions from EGFs

are approximately 47% of the stationary source NOx emissions

in the East Texas Region.

EPA-CAMD commented that the cost effectiveness numbers of

$4,000 per ton of NOx removed in the absence of emissions trading, or $2,000 per ton of NOx removed with emissions trading,

seem far too high. For example, in the May 25, 1999 Final Rule

under §126 of the FCAA (64 FR 28300), EPA determined an average cost- effectiveness of $1,468 per ton of NOx removed from

electric generating units greater than 25 megawatts with emissions trading. Estimates for cost effectiveness of NOx control

under Ozone Transport Committee NOx Budget Program range

from $950- 1,600 per ton. Furthermore, the commenter noted

that some gas-fired units can achieve an average NOx emission

rate of 0.14 lb/MMBtu simply using combustion controls.

The commission supports the preamble language. The listed

values were based on information developed for the joint

Public Utility Commission of Texas (PUCT) and TNRCC report

published in February 1999, entitled Electric Restructuring and

Air Quality: A Preliminary Analysis of Reductions and Costs of

Nitrogen Oxides Controls From Electric Utility Boilers in Texas.

For simplicity in the report, the costs of emission reductions

were analyzed on a unit-by-unit basis. Thus, the potential for

"over-compliance" for certain generating units in cases where it

may be more cost-effective was not captured in the analysis.

A subcommittee of the Ozone Transport Assessment Group

(OTAG) has analyzed market-based emission trading options,

such as the EBTA, estimating potential savings of as much as

50%, compared to the costs of unit-by-unit compliance. This

analysis is applied to all utility generating units in the state,

which may overstate the magnitude of the estimated compliance

costs. The commission believes that, in practice, the costs of

permitting and participation in the EBTA will be much less that

what was estimated in the proposal.

EPA-APD commented on its understanding that the TNRCC will

use emission reductions which occur under these regulations

to help demonstrate attainment and maintenance of NAAQS.

The commenter further understood that the reductions will

not be used for offsets and netting under NSR. With this

understanding, EPA-APD supported the adoption of these

regulations if the TNRCC adequately addresses the remaining

comments.

The EBTA and EGFP programs will be submitted as a revision to

the SIP. The resulting reductions will be used by the commission

to further its attainment goals. Allowances cannot be used to

satisfy emission offset requirements under federal NSR; thus,

they will not be used as netting for PSD or for offsets under a

nonattainment NSR permit.

EPA-APD asked whether standard permits will be incorporated

into a facility’s federal operating permit through 30 TAC Chapter 122’s permit modification provisions. AE recommended that

once an EGFP is issued, any needed revisions to the site’s

federal operating permit (FOP) should be automatically incorporated as administrative corrections and not require an additional

public comment period associated with changes to the FOP.

The commission does not anticipate developing a standard

permit for use by grandfathered EGFs for the purpose of

ADOPTED RULES January 7, 2000 25 TexReg 193
complying with TUC, §39.264. However, a grandfathered EGF

is not prohibited from using any of the standard permits that

are currently available. At this time, the commission’s FOP

program does not include the commission’s NSR program as an

applicable requirement. Only PSD, nonattainment permits, and

case-by-case maximum available control technology (MACT)

review under FCAA, §112(g) or (j), are required to be included

in a FOP as applicable requirements. If and when the EPA

determines that the commission’s NSR program is an applicable

requirement, holders of FOPs may be required to include

references to standard permits in their FOP. If a FOP must

be revised to address changes to applicable requirements as

a result of the EGFP, then, depending on the nature of the

revision, the appropriate revision process under Chapter 122

would be used.

PC recommended substituting renewable energy for electricity or energy used at a grandfathered facility, stating that this

could provide a low cost way to reduce emissions and result

in the building of additional new clean energy sources. The

commenter stated that concurrent rulemaking at the PUCT to

implement the renewable portfolio standard in SB 7 has resulted

in the development of capacity factors and other evaluation procedures that can be useful to the commission in converting renewable capacity to energy for purposes of calculating avoided

emissions and provide for a periodic update for that factor. PC

stated that these rules developed by the PUCT should be incorporated by reference into the commission’s rules.

The purpose of this rulemaking is to obtain emissions reductions

from EGFs based on the specific provisions of SB 7; in

particular, the 50% NOx reductions and the 25% SO2 reductions,

if applicable. These reductions are to be made based on certain

emission rates set forth in TUC, §39.264(h). It is possible that a

grandfathered or electing EGF could make reductions relying on

the use of renewable energy and that the factors developed by

the PUCT may be used to evaluate such a proposal. Since the

commission can consider the rules of the PUCT among many

sources of information to make such decisions, the commission

does not believe it is necessary to incorporate the PUCT rules

into Chapter 101 or 116. The commission agrees that using

renewable energy to achieve emission reductions is a viable

option and one that might result in cost savings to certain

facilities. As the commission continues to develop the permitting

and EBTA programs, issues concerning renewable energy can

be considered. In addition, if a grandfathered or electing EGF

substitutes renewable energy, the resulting emissions should be

lower, requiring less allowances for compliance, thus creating

an economic incentive.

PC believes that the proposed rules will fail to assure that

emissions are actually reduced. PC believes that the utilities are

unlikely to offer a reduction at any plant other than those that are

oldest and used the least. Many of these plants are permitted

as base-load plants which operate 60-80% of the time, but are

kept only for peak use and are used infrequently, less than

20% of the year. Thus, a facility might be glad to modify its

permit by reducing permitted emissions that it would never really

produce. PC recommends that the rule should be modified to

require permit reductions based on the last five years of actual

emissions.

The commission believes that the specified emission rates

in the statute and the corresponding rules will achieve the

target reductions. The intent of SB 7 is to achieve overall

reductions of 50% NOx emissions and 25% SO2 emissions. An

electing EGF would receive allowances equal to actual 1997

emissions, not permit allowable emissions, and would only be

able to generate surplus allowances by reducing emissions

below actual 1997 levels. Also, an electing EGF may not

transfer or bank allowances that are conserved as a result of

reduced utilization or shutdown unless the reduced utilization or

shutdown results from the replacement of thermal energy from

the electing EGF with thermal energy generated by any other

EGF. Further, since SB 7 provides that 1997 is the base year

for determining reductions, the commission does not believe it

has the authority to require permit reductions based on the last

five years of actual emissions. Therefore, the commission has

not changed the rules in response to this comment. Therefore,

the commission has not revised the rule in response to this

comment.

PC commented that the rules adopted for the implementation

of SB 7 should be structured in such a way as to allow the

purchase and retirement of NOx allowables issued under the

SB 7 program to be used as project emission reduction credits

under SB 766. PC recommended two alternatives. First,

the TNRCC could allow a retail electric provider (REP) to

sell renewables to the owner of a grandfathered facility and

assume that there will be a reduction in emissions per megawatt

hour (MW) at the average rate of emissions per MW for the

power plants in the area. The commenter stated that this

is the least costly way to assure that the program will work,

and since Texas is effectively an isolated electrical grid, will

assure that emissions are reduced in the state. The EPA has

recognized the OTAG debates that add-on units that produce

solar electricity or solar water heaters mitigate emissions. PC

argued that a wind turbine, a solar water heater, or gases from

landfills can similarly be rated based on capacity, converted

into energy, and emissions reductions could thus be calculated.

Secondly, TNRCC could allow the REP to buy and retire NOx

credits from the SB 7 trading program established in Chapter

101. This will assure that the emissions are actually reduced

in the 60-county east Texas airshed, but it would add to the

cost. The commenter further stated that since the transaction

is on the open market, it may be far less costly than permit

emission reductions purchased from the competitor; and the

commission can significantly reduce the cost of the renewable

energy used in the program by declaring that the renewable

plants built to meet a contracted load under this program are

pollution control devices as defined in Health and Safety Code,

Chapter 383. If renewable energy installations are certified

under Health and Safety Code, §383.004, the certification will

exempt the owners from property taxes and allow them to qualify

for pollution abatement bonds issued by local governmental

units as provided by Health and Safety Code, §383.021. The

combination of these two financial benefits could erase the

premium price of renewable energy and make it the most costeffective way to reduce emissions.

The commission will explore whether it has the authority to

declare a renewable energy source, such as wind power, to

be a pollution control device for the purposes of property tax

exemptions and pollution abatement bonds. As the EBTA and

permitting programs continue to develop, the commission can

consider issues such as the use of add-on units that produce

solar electricity or solar water heaters to reduce emissions.

The commission agrees that REPs can buy and retire SB 7

allowances under Chapter 101 and that this transaction might

be approved for use as a project emission reduction credit under

25 TexReg 194 January 7, 2000 Texas Register
the VERP program established by SB 766, as long as those

allowances are not used to meet the requirements of SB 7.

One individual commented that health effects reviews should

apply not only for grandfathered plants, but secondary sources

as well.

The rules were not revised in response to this comment. The

permitting program required by TUC, §39.264 does not include

a health effects review. Emissions from grandfathered EGFs

other than NOx

, and for coal-fired EGFs, SO2 and PM may

be permitted using the VERP program requirements. If an

owner or operator chooses to permit grandfathered support

facilities at sites with EGFs, the owner or operator may submit

an application for a VERP under Chapter 116, Subchapter H.

The VERP program provides for a health effects review.

One individual commented that companies have been grandfathered long enough and that the commission should tighten

permitting regulations. SEED and two individuals commented

that grandfathered energy producers should undergo a health

effects review.

Since EGFS are being permitted under the requirements of

TUC, §39.264, which does not require a health effects review,

no review is included in this adoption. The commission believes

that this program will reduce ambient levels of NOx and SO2 and

improve the overall air quality of the state. These reductions will

assist the commission in its efforts to attain the health-based

NAAQS.

MCA commented that all grandfathered power plants should

meet today’s BACT or the federal NSPS for pollutants such as

CO, SO2

, PM, and VOCs, and that this is especially important

in areas such as the HGA region where there is not yet

a demonstration of compliance with the ozone standard and

where the area is bordering violation of the PM standard.

NFN and LWV-TX commented that all grandfathered power

plants should meet today’s BACT or the federal NSPS if

they are located in nonattainment areas or east of IH-35

and north of IH-37. Ten individuals commented that all

grandfathered plants east of I-35 and north of I-37 must be

required to use BACT or NSPS for pollutants such as CO,

particulate, and VOC. One individual also recommended that

the rules require grandfathered power plants to meet BACT

or NSPS for other pollutants, as well as CO, PM10, and

all fluoro-organic compounds. Three individuals commented

that grandfathered plants should use BACT. One individual

commented and supported the comments of SEED and other

environmental groups targeting power plants, and suggested

that the commission require BACT for power plants in the

Metroplex area, require compliance with federal laws, and use

a wide net in a wide geographic area, since pollution comes

from sources far away from Dallas. Two individuals added that

the commission should require reductions in CO and VOC as

well as NOx and SO2

, with one stating that control of radioactivity

should also be included in the adoption. One commenter stated

that the commission should allow no emissions of NOx

, VOC, or

particulate greater than any United States-built power plant.

The commission has made no changes in response to these

comments. SB 7 does not prescribe specific control requirements. However, the commission notes that all EGFs must comply with any applicable NSPS and other federal standards. The

use of BACT is only required if a grandfathered EGF is modified,

consistent with the state or federal definition of "modification."

EGFs applying for a permit under these adopted rules that do

not initiate a modification to the EGF will only be subject to the

specific reduction requirements of TUC, §39.264.They are required to achieve the 50% reduction in NOx or the 25% reduction

in SO2

, whichever is applicable, or meet the reduction requirements through the EBTA. TUC, §39.264 does not specifically

require reductions or permitting of other pollutants; however, the

adopted rules allow for the permitting of other air contaminants

using the control technology and review process established in

Chapter 116, Subchapter H, concerning the VERP program for

grandfathered facilities.

In addition, SB 7 did not distinguish between grandfathered

EGFs located in nonattainment areas versus attainment areas,

nor does it require BACT or NSPS if an EGF is located in a

nonattainment area. The commission has rules that address

emissions from facilities in nonattainment areas, including EGFs

and will be proposing additional rules that will require emission

reductions from EGFs in both nonattainment and attainment

areas east of IH-35 and east of IH-37. The commission will

propose rules that address power plants and other sources in

the DFW area and eastern Texas that will consider the effects

of transport.

PC urged the commission to reduce emissions for all power

plants in the 60-county Texas Clean Air Strategy area to no more

than 0.10 pounds/MMBtu for coal and 0.06 pounds/MMBtu for

natural gas plants. PC noted that the commission estimated in

its February 1999 study that if these standards were adopted,

NOx emissions would drop by 96,000 tons per year. PC

commented that the commission should propose rules at the

earliest possible opportunity that require emission reductions in

the 60-county area east of IH-35 and north of IH-37 to 0.14

pounds/MMBtu because data from the commission and from

OTAG documents that this is the most cost-effective way to

reduce ozone emissions in the state and is less costly than other

options being considered, like inspection and maintenance and

reducing emissions from grandfathered facilities or reformulating

gasoline or buying low emission vehicles. If the commission

were to enact this standard, PC estimates that an additional

80,000 tons per year of NOx would be removed from the airshed.

PC stated that the 0.14 pounds/MMBtu standard was assumed

by the Legislature for the grandfathered facilities and had it been

in place during the ozone season of 1997 and 1998, PC believes

that 40-70% of the ozone exceedances in DFW could have been

avoided. PC added that a level of 0.05 pounds/MMBtu would

reduce even further the emissions from grandfathered units. Six

individuals commented that all power plants should be required

to meet the 0.14 pounds/MMBtu standard for NOx

.

Before the end of 1999, the commission will propose rules

and additional amendments to the SIP that require reduction

in NOX emissions for permitted electric generating utilities and

other industrial sources. The reductions are intended to reduce

the amount of ozone and ozone precursor gases transported

into DFW and other nonattainment areas. These rules will

be proposed concurrently with several other rules as part of

a program to reduce NOX in the eastern portion of Texas.

The commission has identified mobile sources as significant

contributors to ozone levels, particularly in DFW, and intends

to require reductions from these sources as well. The SIP

amendments will target significant emission sources and require

NOX reductions where they will be most effective and do not

unnecessarily burden a particular segment of the economy.

The specific NOX emission limits are also established according

to these goals. The reductions achieved under the adoption

ADOPTED RULES January 7, 2000 25 TexReg 195
of these rules implementing SB 7 will also be a part of this

program.

SEED and PC commented that SB 7 must be read broadly

to require the creation of a de novo permitting standard that

at least provides for parity between Texas-grandfathered plants

and new plants built today. SB 7 strictly indicated that the

Legislature’s intent was to remove special historical exemptions

for older power plants to eliminate unfair competitive advantages

and excess pollution, and that in SB 7, the Legislature intended

that grandfathered units face the same permitting hurdles as

those faced by new plants built today. TUC, §39.264(e) requires

that grandfathered units must apply for de novo permits on

or before September 1, 2000. TUC, §39.264(f) requires the

TNRCC to develop rules for this permitting process. TUC,

§39.264(g)-(j) instructs the TNRCC to also develop a system

for allowances for sulfur and nitrogen emissions and set forth

specific starting allowance formulas. The commenters stated

that nowhere did the Legislature indicate that the TNRCC

should not exercise its general organic authority in existing

regulatory framework in reviewing and acting upon these de

novo permit applications. The Legislature went even further

and stated that it does not intend to "limit the authority of the

TNRCC to require further reductions of nitrogen oxides, sulfur

dioxide, or any other pollutant from generating facilities subject

to" the law. Additionally, the Legislature provided for stranded

cost recovery of unit cleanup costs. Finally, the Legislature

also authorized cost recovery where the "amount and location

of resulting emission reductions is consistent with the air quality

goals and policies of the TNRCC." The commenters also stated

that de novo permitting of grandfathered facilities should include

at least NSR for NOx and SO2 as well as appropriate limits for

air toxics and mercury, and that grandfathered facilities should

at least meet the NSR performance requirements that would

have to be met by new coal or gas plants sited in Texas

today. Reasons for this include concerns with ozone, nitrogen

enrichment in estuaries, acid deposition, haze, PM2.5, and

mercury and other hazardous air pollutants. SEED included

health effects and coal combustion wastes. PC commented

that, in particular, the rules should provide that EGFs be treated

as would any new coal, oil, or gas power plant applying for de

novo permitting. At a minimum, the TNRCC should thus require

EGF’s seeking permitting under the rules to meet BACT or

lowest achievable emission rate (LAER) standards for NOx and

SO2 depending on whether the units are located in an attainment

or nonattainment area. In addition, the TNRCC should require

these applying plants to meet appropriate net carbon dioxide

limits and toxic emission limits for mercury and other air toxics.

SEED and PC commented that the TNRCC should take supplemental comments on specific performance criteria to be met

under de novo grandfathered facility permitting. In its narrative

to the present proposal, the TNRCC states that if it embraced

permitting standards beyond the minimum specified in SB 7, it

"is unclear what standards these air contaminants should be

held to." SEED commented that it is reasonably possible for

these standards to be developed, and for nitrogen and sulfur

that BACT and LAER provide an appropriate departure point.

SEED and PC recommended that further supplemental comments be solicited in the second phase of this proceeding to allow for a more detailed discussion. SEED and PC commented

that they are in support of the provisions in proposed §116.911

and §116.913, in that they retain the TNRCC’s authority in the

de novo permitting process.

The commission does not agree that the intent of TUC, §39.264

was to require de novo permitting of EGFs under the TCAA.

While TUC, §39.264(e) requires EGFs to apply for a permit on or

before September 1, 2000, that section goes on to say that the

permit shall require the EGF to achieve emission reductions or

allowances as provided by §39.264. TUC, §39.264(h) provides

specific direction to the commission to base allowances on 1997

heat input, and it states emission rates for each of the defined

regions. The heat input formulas were designed to achieve

the 50% NOx reductions and the 25% SO2 reductions. The

commission does not believe that it is appropriate to revise

those formulas to require further reductions from grandfathered

EGFs under the SB 7 program. The provisions of TUC, §39.264

do not specifically prohibit the commission from relying on the

permitting requirements of the TCAA; however, the commission

believes that had the Legislature intended this result, it would

have placed the EGF permitting requirements in TCAA, Chapter

382. In fact, early drafts of SB 766, which did amend the

TCAA, contained the permitting and allowance provisions for

EGFs. Even though the EGFs included in an EGFP will not

undergo a BACT and impacts analysis for initial issuance,

future modifications to the EGFs themselves will be required

to be processed under Subchapter B of Chapter 116. The

permitting and EBTA programs will achieve a certain amount

of reductions based on the provisions of TUC, §39.264. The

provision in TUC, §39.264(s) recognizes that the commission

has the existing authority to require additional reductions from

EGFs. The commission does not believe that this section was

intended to support further reductions from EGFs under the

SB 7 program. Rather, it appears that the section was worded

to recognize the fact that under existing law, the commission

may require additional reductions from EGFs through other

commission rules, such as the reasonably available control

technology rules.

Even though EGFPs will not be issued using the procedures

in the TCAA, these permits will not authorize noncompliance

with any applicable state or federal standards, including NSPS,

NESHAPS, MACTs, and federal NSR permitting requirements.

The commission does not believe that it is appropriate to require

grandfathered EGFs to meet the NSPS for new coal or gas

plants, or to meet BACT or LAER, depending on location.

As previously noted, TUC, §39.264 provided specific emission

rates and goals that are to be used to implement the program.

If a grandfathered EGF has made a major modification under

the PSD or nonattainment NSR programs, then the facility must

comply with those programs. This is a separate requirement

from SB 7 and is not negated by the issuance of an EGFP.

Section 116.910(e) provides that emissions of air contaminants

other than NOx

, and if applicable PM and SO2 may be permitted

by an EGFP if the grandfathered EGFs meet the requirements

of Chapter 116, Subchapter H, concerning VERPs. Section

116.910(f) provides that other grandfathered facilities at a site

may be permitted in an EGFP if these facilities meet the

requirements to obtain a VERP. SB 7 does not require the

permitting of any air contaminants other than NOx

, and if

applicable PM and SO2

. Therefore, the commission chose to

rely on the VERP program created by SB 766 to provide a

basis of review for other air contaminants from grandfathered

EGFs or grandfathered facilities so that all facilities at a site

may be permitted. SB 766 provides specific control and other

requirements for the permitting of grandfathered facilities. Since

the Legislature passed SB 7 and SB 766 during the same

session, the commission believes it is appropriate to review

25 TexReg 196 January 7, 2000 Texas Register
the grandfathered facilities and the other emissions from a

grandfathered EGF using the VERP process. The commission

does not believe that it is necessary to take additional comments

on this issue at this time.

CSW, Entergy, Entergy Services, Reliant, CPS, Group A, and

AECT commented that the permitting program as described

in proposed §§116.911-116.913 is contrary to the permitting

program contemplated by §39.264 of SB 7. The commenters

stated that based on the language in §39.264 and the legislative

history underlying it, it is clear that the SB 7 permitting program

is supposed to be very different than the existing commission

NSR permitting program. However, the SB 7 permitting

program that proposed §§116.911-116.913 would establish is

very similar to the existing commission NSR permitting program

and clearly was patterned after the language in §116.111 and

§116.115 of the NSR permitting program. CPS noted that in SB

7, the Legislature envisioned a program similar to EPA’s Acid

Rain Program.

The commenters stated that the existing NSR permitting program is a review-intensive, command and control system. Under the existing NSR permitting program rules, a permit application is subjected to a detailed and complex review that includes a BACT review, off-site impacts review, and a review to

determine compliance of the proposed new or modified facility

with NSPS, NESHAPs, and other state and federal air quality

rules. TUC, §39.264 clearly provides that an EGF may meet

its NOx and/or SO2 allowance(s) without adding or implementing any emissions control whatsoever. Instead, §39.264 provides that an EGF may meet its NOx and/or SO2 allowance(s)

through emissions trading, in lieu of adding or implementing

emissions controls. Moreover, nothing in §39.264 specifies, or

even indicates, that if the owner/operator chooses to add or implement emissions control to cause the EGF to meet its NOx

and/or SO2 allowance(s), that any commission review of such

emissions control is to be conducted or that the commission

must approve of such control. The commenters further stated

that TUC, §39.204 establishes a permitting program that gives

owners/operators of EFGs great flexibility in their use of NOx

and/or SO2 allowances in exchange for severe penalties if they

do not comply with their allowable allocation. AE believes that

the permit program envisioned under §39.264 should be designed to be very simple and straightforward. AE believes that

the application should be very short if the applicant chooses

to use the FCAA required continuous emission monitoring systems (CEMS) and will use allocations derived from the Acid

Rain Database.

Based on the foregoing reasons, the commenters believe that

§§116.911-116.913 should be significantly simplified so that

the SB 7 permitting program is less like the review-intensive,

command control approach of the existing NSR permitting

program, and more like the flexible permitting program that

is described by the language of §39.264 of SB 7 and was

contemplated by the Texas Legislature when it drafted and

passed SB 7.

The commission agrees with the commenters that the permitting

program required under TUC, §39.264 is narrowly constructed

to permit grandfathered EGFs and to achieve a target reduction of NOx and, if applicable, SO2

. The commission has made

significant revisions to the sections in Chapter 116, Subchapter I that have simplified the application content sections and

in general, the requirements of the permit program. For example, the requirements to demonstrate compliance with federal

standards have been deleted. Further, the provisions regarding

control methods in §116.911(a)(2) have been rewritten to address applications that propose new control technology in order

to meet the emission limitations of TUC, §39.264. Subsection

(a) now refers to the standard permit for the installation of controls as the basis for the review that will be used by the commission to approve these new controls. The specific revisions

and responses to comments for §§116.911-116.913 follow this

response.

EPA-APD commented that §§116.911(a), 116.914(f)(2), and

116.915(b) refer to miscellaneous forms. The commenter

stated that the TNRCC should address why these forms are

not included in the proposed rulemaking and subject to public

review and comment.

The text of the application forms are not part of the rules;

however, the commission welcomes comment at any time

whenever forms, instructions, and guidance documents can be

improved or clarified. Section 116.915, concerning Emission

Control Changes, has been deleted from the adopted rule

package for reasons discussed elsewhere in this adoption

preamble.

B&P commented that §116.18(2)(B) should be revised so that

the EGF’s maximum design heat input is measured in MMBtu

per hour versus MMBtu to calculate capacity factor.

The commission agrees, and has revised the definition of

"Capacity factor" in §116.18(2)(B) accordingly.

Reliant commented that §116.910(a) should be revised as

follows: "The owner or operator of a grandfathered facility (as

defined in 116.10 of this title (relating to general definitions)) at

sites with EGFs ...." As proposed, the word "grandfathered" is

not defined in this section of the regulations. The commenter

suggested that the commission refer to §116.10 to avoid

ambiguity.

The commission has not revised §116.910(a) in response to

this comment. The commission instead chose to revise the

definition of "Electric generating facility" and to include a definition of "Grandfathered EGF" to make a clear distinction that

a "Grandfathered EGF" means an EGF that is not subject to

the requirement to obtain a permit under TCAA, §382.0518(g).

Section 116.910(a) was also revised in response to this comment.

Lloyd Gosselink commented that §116.910(a) does not apply

to municipal utilities or electric cooperatives. TUC, §39.002

(Applicability) provides that Chapter 39 (except for §§39.157(e),

39.203 and 39.904) does not apply to a municipally-owned

utility or an electric cooperative. Thus, TUC, §39.264 does

not apply. Lloyd Gosselink recommended that §116.910(a) be

revised to read: "The owner or operator of a grandfathered

electric generating facility (EGF) shall apply for a permit to

operate that facility under this Subchapter. This requirement

does not apply to a municipally owned utility or an electric

cooperative." PC commented that SB 7 requires emission

reductions from grandfathered power plants owned by investors

or municipalities.

The commission has made no changes in response to this comment. TUC, §39.002, addresses the applicability of Chapter

39, Restructuring of Electric Utility Industry. That section excludes "municipally owned utilities" and "electric cooperatives"

from the requirements of Chapter 39, with some exceptions.

TUC, §39.264 was added to SB 7 during the final days of the

ADOPTED RULES January 7, 2000 25 TexReg 197
legislative session. Its very specific intent is to require grandfathered EGFs to obtain a permit from the commission and to

obtain reductions of NOx and SO2 in the regions as defined by

the bill.

The Code Construction Act, §311.021, Texas Government

Code, provides that "In enacting a statute, it is presumed that:

(1) compliance with the constitutions of this state and the United

States is intended; (2) the entire statute is intended to be

effective; (3) a just and reasonable result is intended; (4) a

result feasible of execution is intended; and (5) public interest

is favored over any private interest." Although the commenter

is correct in noting that TUC, §39.002 specifically excludes

municipally owned utilities, that section must be read in context

with the rest of Chapter 39.

TUC, §39.264 defines an "electric generating facility" as a facility that generates electricity for compensation and is owned

or operated by a person in this state, including a municipal corporation, electric cooperative, or river authority. No definition

of "municipal corporation" is provided in SB 7; thus, it is appropriate to consider the definition of "municipally owned utility"

for guidance on what was intended to be covered by the term

"municipal corporation." The term "municipally owned utility" is

defined in TUC, §11.003(11) as a "utility owned, operated, and

controlled by a municipality or by a nonprofit corporation the directors of which are appointed by one or more municipalities."

It is reasonable to interpret the term "municipal corporation" to

be the same as the term "municipally owned utility," since the

terms are both used in the context of the electric utility industry in SB 7. Since the definition of "electric generating facility"

includes "municipal corporations," it is appropriate to conclude

that the Legislature intended for municipal corporations to be

specifically included in the permitting program. The Legislature

specifically noted exceptions for applicability in TUC, §39.264,

and in spite of the undefined term "municipal corporation," the

commission believes that the specific permitting requirements

of TUC, §39.264 control over the general applicability requirements of TUC, §39.002. By interpreting TUC, §39.264 in this

manner, a just and reasonable result occurs, since the interpretation enables the affected sections of Chapter 39 to be effective. The exemption provided by TUC, §39.002 allows municipal

utilities and electric cooperatives to be exempt from the deregulation provisions. Municipal corporations and electric cooperatives with EGFs with nameplate capacities of 25 megawatts or

less are not required to participate in the EBTA or the permitting program. Those over that amount must obtain permits and

participate in the EBTA. Since TUC, §39.264 does not specifically exempt municipal corporations and electric cooperatives

with EGFs with nameplate capacities over 25 megawatts, the

commission does not believe it is appropriate to exclude those

EGFs. The commission believes that the applicability exceptions in TUC, §39.002 are intended to exempt EGFs from the

competition provisions of Chapter 39, not the permitting program.

EPA-ARD commented that various paragraphs in §116.910 are

not clear as to who is taking action. For example, subsection

(b) presumes that it is the owner or operator, and subsection

(e) presumes that it is the commission.

The commission believes that clarification of the rules is warranted. The commission believes the proposed rule was clear

as to who was taking action in §116.910(b), concerning electing

facilities; however, to ensure clarity, the commission has revised

subsection (b) to include a reference to "owners or operators."

The commission has not revised §116.910(e), since that subsection was intended to address which air contaminants can be

permitted under the requirements of Subchapter H and which

may be permitted using the procedures in Chapter 116, Subchapter I, concerning the VERP program.

Reliant, TXU, Brazos Electric, Entergy, Entergy Services, Group

A, AECT, and CPS commented that electing EGFs should not

be subject to a full permit review as part of their electing,

but that instead, their allowances should be issued through a

permit alteration. The commenters stated that the proposal’s

requirements for electing EGFs are far more complex than

intended in SB 7. SB 7 only requires that electing EGFs must

be allocated NOx and SO2 allowances and that they specify the

identity of the electing EGFs. SB 7 has no other requirements

for electing EGFs. The commenters stated that §116.910(a)

and (b) and §116.913 should be revised to meet these goals.

A similar comment was received from EPA-APD, noting that

§116.912 should be clarified that all conditions in the existing

permits of electing EGFs should continue to apply and are

carried into the EGF permit. The TNRCC must authorize any

changes or revisions to the conditions of the existing NSR

permit (including PSD and nonattainment (NA) review permits)

consistent with Chapter 116, Subchapter B.

The commission believes that SB 7 allows an EGF not covered

by TUC, §39.264 to become subject to the requirements of TUC,

§39.264, which include the requirement to obtain an EGFP.

The commission agrees that the process to include electing

EGFs in the Subchapter I permitting program can be simplified.

Accordingly, the commission has revised §116.910(b) to allow

for the electing EGF’s NSR permit to be altered consistently

with the requirements for alterations in §116.116(c). Electing

EGFs must notify the commission of their intent to be included

in the EGF permit program under Subchapter I for the purpose

of obtaining allowances for NOx and, if applicable, SO2

. The

commission believes that it is necessary to alter the NSR

permit to include a cross-reference to the EGFP. Electing EGFs

must submit a separate application by September 1, 2000.

After reviewing both the application for the EGFP and the

alteration, the EGFP that goes to public notice will include

only those conditions that are required under Subchapter I.

The terms and conditions of the altered NSR permit will

not be subject to public notice. The EGFP may include

certain provisions from the NSR permit that are necessary

to ensure compliance with the allowance system. Because

the rule has been revised to include the permit alteration

procedures, the references to "combined permits" have been

deleted from §116.18(4) and §116.912(a)(3) and (4) and (b)(6).

Further, to simplify the provisions for electing EGFs, many of

the provisions in §116.912, concerning application content for

electing EGFs, were moved to §116.911. Section 116.912(b) is

now §116.912(a) and contains the provisions for opting in and

out of the permitting program.

EPA-APD commented that §116.910(b) requires electing facilities to consolidate existing NSR terms into the EGFP. EPA-APD

interpreted this to include all applicable terms of the existing

NSR permit, including terms and conditions of PSD, nonattainment, and minor NSR permits. EPA- APD requested confirmation of this interpretation.

As discussed previously in this adopted preamble, the commission has deleted the procedures for combining NSR permits

with EGFP from the adopted rule. Since the existing NSR permits will only be altered to include a reference to the EGFPs for

25 TexReg 198 January 7, 2000 Texas Register
the electing EGF, the terms and conditions of the NSR permit

will continue to apply.

EPA-ARD suggested moving §116.910(c) closer to the beginning, since it is basic to the entire section.

The commission has made no changes in response to this

comment. The commission believes that the organization of

§116.910 is clear as to the rule’s applicability.

LP&L requested that the commission add the following sentence

to §116.910(d): "If the municipal cooperation, electric cooperative, or river authority reevaluates its intent to exclude the Electric Grandfathered Facilities (EGFs) it notified the commission of

prior to January 1, 2000, it may choose to elect to permit any of

those EGFs at a later date." LP&L believes that this statement,

if added, would bring more exempted EGFs into the emissions

trading and allowance program after they have had a chance

to fully evaluate the compliance costs associated with the EGF

permit.

The commission believes that a municipal corporation, electric

cooperative, or river authority with grandfathered EGFs with

a nameplate capacity of 25 megawatts or less or electing

EGFs owned by these entities can decide to participate in

the permitting program under Subchapter H at a date later

than January 1, 2000, by using the provisions in §116.912,

concerning electing EGFs. However, applications for EGFPs

must be submitted by September 1, 2000. Section 116.910(d)

has been revised to allow municipal corporations, electric

cooperatives, or river authorities to reevaluate their decision

to exclude certain EGFs and to participate in the permitting

program. Further, §101.333(4)(A)(ii), now §101.333(5)(A)(ii),

has been revised to provide that allowances for municipal

corporations, electric cooperatives, or river authorities, that

choose to participate in the permitting and EBTA program, will

be issued by January 1, 2001.

B&P commented that §116.910(e) states that the permitting requirements apply to "any EGF" or "coal fired EGFs." The commenter stated that this language should be revised to provide

that the permitting requirements apply only to grandfathered and

electing EGFs, and that "emissions of other air contaminants

from EGFs ...," should be changed to refer to only grandfathered EGFs. EPA- ARD commented that clarification is needed

in §116.910(e) on whether the trading program only applies to

coal-fired facilities, since only coal-fired EGFs are permitted for

SO2

.

The commission agrees, and has added the term "grandfathered and electing EGFs" to §116.910(e). The rule has also

been revised to clarify that emissions other than NOx , SO2

, or

PM from grandfathered EGFs may be permitted using an EGFP,

provided that the conditions of Subchapter H are met concerning VERPs. The EBTA applies to grandfathered and electing

EGFs that emit NOx and, if coal- fired, SO2

.

CSW, Reliant, TXU, Lloyd Gosselink, CEED, Entergy Services,

and AECT commented on §116.910(e) and §116.913(a) that

the TNRCC does not have statutory authority to impose tenyear old BACT on contaminants other than NOx and SO2

. CSW

commented that the intent of SB 7 is to permit all other air

contaminants at their existing (grandfathered) allowables. LP&L

commented that §116.913(a)(1)(C) and all other references to

EGFs meeting the requirements of Chapter 116, Subchapter H,

should be deleted from the proposed regulations, and that the

language as stated in SB 7 does not authorize the commission

to apply emission control standards other than NOx and SO2

.

The legislation also does not authorize the commission to

develop and regulate EGF permits as those permits in the VERP

program. B&P commented that §116.913(a)(1)(C) provides that

each EGFP will include a general condition that authorizes

emissions of air contaminants other than NOx and SO2 from

EGFs meeting the requirements of Chapter 116, Subchapter H.

The commenter stated that the section should be revised, since

emissions of other air contaminants from electing EGFs will not

be authorized under Chapter 116, Subchapter H.

The permitting program established by SB 7, which is contained

within the TUC rather than the TCAA, addresses only emissions

of NOx

, SO2, and, by including a standard for opacity, PM.

Other pollutants, such as VOC and CO, were not addressed

and therefore, are not required to undergo a permitting process

under TUC, §39.264. The commission believes the intent

of SB 7 was also to eliminate the grandfathered status of

EGFs. However, SB 7 did not specify the criteria for permitting

air contaminants other than those addressed by SB 7, nor

does it require the permitting of other air contaminants from

grandfathered EGFs. The commission believes that it is not

appropriate to merely include the existing allowable emission

rates for emissions other than NOx

, or, if applicable, SO2 for

grandfathered EGFs in an EGFP. This is consistent with the

commission’s longstanding policy to not treat certain facilities as

being "permitted" simply because the facilities are consolidated

into an existing permit. For example, a facility that was originally

authorized by an exemption will continue to be authorized under

the exemption even though the exemption is consolidated with

an NSR permit during an amendment or at renewal. Since

the Legislature passed SB 7 and SB 766 during the same

session, the commission believes that it is appropriate to review

the grandfathered facilities and the emissions of contaminants

not addressed by SB 7 from a grandfathered EGF using the

VERP process. SB 766 provides specific control and other

requirements for the permitting of grandfathered facilities. In

order to provide an option for the complete permitting of

grandfathered EGFs under the TCAA, §116.910(e) provides that

emissions of air contaminants other than NOx

, SO2, and PM may

be permitted by an EGFP if the grandfathered EGF meets the

requirements of the VERP program. Section 116.910(e) does

not require grandfathered EGFs to permit emissions other than

NOx

, SO2, or PM. The choice to permit other air contaminants

from grandfathered EGFs or grandfathered non-EGFs remains

with the applicant. The rule provides that if those emissions or

non-EGFs are to be permitted, they will be reviewed using the

VERP process. Section 116.913(a)(1)(C) has been deleted. A

new §116.913(a)(2) and (3) is included in the final rule. Section

116.913(a)(2) provides that an EGFP may permit emissions of

all other air contaminants from grandfathered EGFs, provided

the EGFs meet the requirements of the VERP program. Section

116.913(a)(3) allows grandfathered EGFs to consolidate a

VERP with an EGFP.

EPA commented that §116.910(e) states that "other contaminants may be permitted ...." EPA-APD asked if this means

that a facility can remain grandfathered for VOC, PM, CO,

and lead. Secondly, EPA-APD stated that it appears that

§116.913(a)(1)(C) requires inclusion of these contaminants in

the permit.

The permitting program established by SB 7, which is contained

within the TUC rather than the TCAA, addresses only emissions

of NOx

, SO2, and, by including a standard for opacity, PM.

ADOPTED RULES January 7, 2000 25 TexReg 199
Other pollutants, such as VOC and CO, were not addressed

and therefore, are not required to undergo a permitting process

under TUC, 39.264. Because the TCAA requires that facilities

rather than pollutants be permitted, the EGF itself would remain

grandfathered since not all emissions from the EGF would have

been through a permit review process. In order to facilitate the

permitting of grandfathered EGFs under the TCAA, §116.910(e)

provides that emissions of air contaminants other than NOx

,

SO2

, or PM may be permitted by an EGFP if the grandfathered

EGFs meet the requirements of Chapter 116, Subchapter H,

relating to VERP, which provides specific control and other

requirements for the permitting of grandfathered facilities. Since

the Legislature passed SB 7 and SB 766 during the same

session, the commission believes that using the VERP process

is appropriate to review the pollutants not addressed by SB 7.

The adopted rule does not require owners or operators to permit

the other pollutants from grandfathered EGFs. This is an option

that may be exercised by the owner or operator. As stated

previously in this adopted preamble, TUC, §116.913(a)(1)(C)

was deleted.

EPA-ARD commented that clarification is needed in §116.911(a)

regarding the definition of "authorized representative" and asked

if this is the same person as "authorized account representative."

The authorized representative referred to in §116.911(a) is any

person who is authorized to sign a form PI-1-U on behalf of

the applicant. This requirement is consistent with §116.111,

concerning general applications for permits under Chapter 116.

The "authorized account representative" is the person who is

authorized to transfer or otherwise manage allowances under

Chapter 101 concerning the EBTA. The rule has not been

revised in response to this comment.

Reliant commented that references to other applicable requirements (i.e., nonattainment, PSD, and §112(g)) are unnecessary and should be deleted. However, if retained, Reliant recommended that the language be revised to clarify that these

programs would apply only if the EGF is undergoing a modification or other action triggering applicable requirements. B&P

commented that §116.911(a)(3) and (4) should simply state

that the proposed Subchapter I cannot be used to authorize

construction or operation of a new source or a modification of

an existing source. EPA-APD commented that §116.911(a)(3),

(4), and (5) require an EGF to comply with applicable requirements of nonattainment review, PSD, and reconstructed major

sources. The commenter stated that these provisions apply

to new and modified sources and do not appear to apply to

"grandfathered sources," and that these provisions may apply

to sources which elect to opt into the program. EPA- APD further commented that first, these sections must also ensure that

an electing source continues to meet all applicable provisions.

Secondly, the TNRCC must add "applicable requirements of the

Texas State Implementation Plan including such provisions as

reasonably available control technology."

Lloyd Gosselink commented that §116.913(a)(9) should be

deleted, because NSPS requirements are imposed on facilities that were constructed or modified after the publication

of the applicable standard. The commenter also stated that

§116.913(a)(10) should be deleted, because NESHAPS requirements are imposed on facilities that were constructed

or modified after the publication of the applicable standard.

Lloyd Gosselink also commented that §116.913(a)(11) should

be deleted, because the requirements for NESHAPS for source

categories are imposed on facilities that were constructed or

modified after the publication of the applicable standard.

The commission has revised the rule in response to these

comments. Section 116.911(a)(3)-(5)and §116.913(a)(9)-(11)

have been deleted. These paragraphs dealt with NSPS,

NESHAPs, NESHAPs for source categories, nonattainment

review, PSD review, and construction or reconstruction of major

sources of hazardous air pollutants. The commission agrees

that TUC, §39.254 does not require EGFs to address the

applicability of, or compliance with, federal standards as a

condition of obtaining an EGFP or for participation in the EBTA.

However, even though these paragraphs have been deleted,

EGFs must still comply with these federal standards, if they are

applicable. If, during the review of an application for an EGFP,

the commission discovers that an EGF is out of compliance

with any federal standards, the commission will initiate the

appropriate enforcement action.

CSW, Entergy Services, and AECT commented that

§116.911(a)(1) should be deleted in that such requirements are adequately addressed in §116.914 except for cases

where alternative monitoring methods are used. CSW also

commented that §116.914(d) should be revised to require

submission of information to support alternative monitoring

requests as soon as possible, but not later than May 1, 2002.

The commission has revised §116.911(a)(1) in response to this

comment to clarify that an application must contain sufficient

information for the commission to evaluate the proposed monitoring. The commission does not believe that this subsection

should be deleted, since information is needed to know what

emissions monitoring and reporting requirement the applicant

has chosen. In addition, if the applicant is submitting a plan

to comply with §116.914(d) (now §116.914(b)), it is necessary

for the commission to review and approve the monitoring plans.

The commission believes that the initial application submitted by

September 1, 2000 should include contain sufficient detail regarding alternative monitoring requests. The commission needs

sufficient time to review all monitoring proposals to ensure consistency and reliability. During the application review process,

the commission will work with applicants to further refine the

alternative monitoring proposal as necessary. The commission

has not revised §116.914(d) (now §116.914(b)) in response to

this comment.

AECT and Entergy Services commented that §116.911(a)(6)

should be deleted because the proposed §116.911(a)(6) does

not relate to grandfathered facilities, but rather to the use of

standard permits described in §116.915 for pollution control

projects. The commenters stated that in many instances, use

of the §116.915 standard permit will not occur by September 1,

2000, the date the SB 7 permit application is due. Therefore,

it will not be possible in many cases to include in the SB 7

permit application the information requested in §116.911(a)(6).

B&P commented that in §116.911(a)(6), there is a reference to

§116.915(b)(2), which does not exist. Also, B&P commented

that §116.911(a)(6) is not necessary because there should

be no rules that require air quality impacts analysis where

there is an increase in emissions. TXU also commented

that §116.911(a)(6) should be deleted because that language

is not supported by §39.264 of SB 7. SB 7 does not

impose any type of control technology, but specifically allows

flexibility to determine what controls, if any, will be used to

achieve necessary reductions. For the same reason, Reliant

commented that certain parts of §116.915 should be revised

25 TexReg 200 January 7, 2000 Texas Register
to be consistent with §116.617 (Standard Permit). Specifically,

§116.915 deviates from §116.617 in two respects. First, the

review time should be 30 days, not the proposed 45 days;

second, the proposal omits the language allowing for emission

increases associated with a derate resulting from the installation

of control equipment. Reliant commented that the proposed

§116.915(d) does not have a counterpart in §116.617, and

should be deleted, or state that these federal requirements

apply if the EGF is undergoing a modification or other action

triggering review under these requirements.

The commission has deleted §116.915 from the adopted rules

in response to these comments. The commission will withdraw

this proposed section. Since Chapter 116, Subchapter F,

§116.617, Standard Permits for Pollution Control Projects,

already provides the procedures for installing pollution control

projects, it will simplify the adopted rule to include a crossreference in §116.911(a)(2) to specific sections in Chapter 116,

Subchapter F. The commission has revised §116.911(a)(6) (now

§116.911(a)(3)) to delete the reference to §116.915 and to refer

to the new §116.911(a)(2), regarding controls. This paragraph

is necessary, because the commission may require modeling or

monitoring to ensure public health and safety when evaluating

proposed controls which cause an increase in emissions.

CSW, Reliant, TXU, Entergy, Entergy Services, B&P, Group

A, AECT, and CPS commented that §116.911(a)(2) should be

deleted, because that language is not supported by §39.264

of SB 7. The commenters stated that SB 7 does not impose

any type of control technology, but specifically allows flexibility to

determine what controls if any will be used to achieve necessary

reductions.

The commission agrees that the TNRCC cannot require a

grandfathered or electing EGF to use any specific control technology to ensure that their actual emissions do not exceed their

allotted allowances. However, the commission does believe that

if controls are going to be used to meet their emission requirements, the commission must ensure that the requirements of

§116.911(2) are met. The language in §116.911(a)(2) has been

revised to reference §116.617, regarding the requirements for

pollution control projects, which will provide the commission sufficient information on any proposed emission controls. The requirements in §116.617 are intended to allow for the addition

of new controls in a streamlined manner while ensuring that

any associated emission increases will not cause adverse offproperty health impacts.

EPA-ARD commented that §116.911(b) would be clear if stated

in the active voice, and recommended the following language:

"The owner or operator of a grandfathered EGF must submit an

application for a permit on or before September 1, 2000." EPAARD also commented that "Grandfathered EGF" is not defined.

The commission agrees that the suggested language is clearer,

and has revised the rule. The revised language is now in

§116.911(c). The commission has also defined the term

"Grandfathered EGF" in §116.18(9).

B&P commented that §116.911(c) should be revised to provide

that applications for EGFP must be submitted under the seal of

a professional engineer (P.E.) only when the capital cost of the

project is greater than $2 million as provided in §116.110(e).

AE questioned the need for a P.E. seal (in §116.911(c)) on

a streamlined application, and stated that a P.E. seal may

be required if the applicant chooses an alternate means of

demonstrating compliance, such as one that would require

specific engineering calculations.

The commission agrees that submittal of an EGFP application

under the seal of a licensed P.E. should be done only in

accordance with §116.110, as was the intent of the proposed

§116.911(c). The commission has reworded this concept to

clarify the intent, and moved the language to §116.911(d).

B&P commented that §116.912(a) states that electing EGFs

shall submit an application "to authorize" NOx and SO2 emissions. The commenter stated that the TNRCC needs to revise

this language, since electing EGFs are already authorized under their NSR permit.

The commission agrees that electing EGFs already had authorization to emit NOx and SO2

; however, submitting an application

under Chapter 116, Subchapter I is requesting a new authorization for NOx

, and if applicable SO2. This authorization is

necessary to allow the electing facility to obtain allowances and

to participate in the EBTA. The commission believes that this

is consistent with the requirements of TUC, §39.264(i). Therefore, the rule has not been revised in response to this comment.

The commission notes that the NSR authorization for the NOX,

and if applicable, SO2 and PM from electing EGFs continues in

effect as enforceable permit conditions. Section 116.912(c)(1)

and (2) was moved to §116.911(a)(3) in order to consolidate the

application requirements for grandfathered and electing EGFs.

EDF commented that §116.912(b) allows electing EGFs to opt

out of the program, and that this is not allowed in SB 7, but

appears to have been added to offer additional flexibility to utility

companies. The commenter stated that facilities have ample

time to decide whether or not to opt in, and that this provision is

not necessary. EDF commented that if the TNRCC chooses to

revise the provision, the commission should allow electing EGFs

to opt out only before the first control period. One individual

commented that once an EGF opts into the program, it should

always be in.

The rule has not been revised in response to these comments.

The commission agrees that TUC, §39.264 does not expressly

provide for electing EGFs to opt out of the program. However,

opting out is not prohibited. Since electing EGFs are voluntarily

participating in the program and are already authorized by

a NSR permit, emissions reductions will not be jeopardized

by allowing opting out. The commission believes that it is

appropriate to allow electing EGFs to notify the commission

of the decision to opt out prior to the beginning of the next

control period. As the implementation of the permitting and

allowance program proceeds, future rules and regulations may

require operational changes at electing EGFs that may not be

consistent with its allowances. Further, electing EGFs may

modify a facility, thereby making its participation impracticable.

The commission believes that it is appropriate to give this

flexibility to an owner/operator who voluntarily participates in

this program. The provisions for opting out of the program are

now in §116.912(a).

B&P commented that §116.912(b)(1) and (2) should be replaced with the statement that an electing EGF’s decision to

opt out will become effective at the beginning of the control period following notification of the TNRCC. The commenter also

stated that proposed §116.912(b)(3), (4), and (6) should be revised so that each begins with the statement, "once an EGF

has opted out."

ADOPTED RULES January 7, 2000 25 TexReg 201
The provisions in §116.912 have been reorganized in response

to this comment. The commission agrees that the rule should

address when the decision to opt out will become effective and

has included that language.

EPA-APD commented that §116.913(a)(1)(B) should clearly

define a coal-fired EGF that is subject to limitations of SO2

.

The commenter stated that it is clear that the rule applies to

EGFs that fire 100% coal, but that the rule should further clarify

whether these requirements apply to EGFs which fire coal in

combination with other fuels and EGFs which are capable of,

but not presently firing coal.

The commission has not revised §116.913(a)(1)(B) in response

to the comment. The commission agrees that it is appropriate

to define "coal" and "coal-fired," and has revised §101.330 and

§116.18 to include the following definitions: (1) "Coal" means all

solid fuels classified as anthracite, bituminous, subbituminous,

or lignite by the American Society for Testing and Materials

Designation ASTM D388-92 "Standard Classification of Coals

by Rank" (as incorporated by reference in Title 40 Code of

Federal Regulations, §72.13 (effective June 25, 1999)); (2)

"Coal-fired" means the combustion of fuel consisting of coal

(as defined in §116.18(3)) or any coal-derived fuel (except a

coal-derived gaseous fuel with a sulfur content no greater than

natural gas), alone or in combination with any other fuel. The

definition is independent of the percentage of coal or coalderived fuel consumed during any control period.

EPA-APD commented that it is not clear how §116.913(a)(2)

differs from §116.913(a)(1), and that if the intent is to consolidate for sources other than an EGF, e.g., a non- related boiler,

it may be more clear to include the distinction in the rule.

Proposed §116.913(a)(2) (now §116.913(a)(3)) provided that

the owner or operator of grandfathered facilities could consolidate the EGFP with a VERP issued under Chapter 116, Subchapter H. Proposed §116.913(a)(1) set out the applicability of

the EGFP and stated that it authorized NOx from all grandfathered or electing EGFs and, where applicable, SO2

. Section 116.913(a)(1)(C) provided that emissions from EGFs besides NOx or SO2 could be permitted using the requirements

of the VERP program. The rule has been revised to separate

§116.913(a)(1)(C) and to create a new §116.913(a)(2). This

clarifies that the VERP requirements are not part of the mandatory EGFP program.

Reliant commented that §116.913(a)(5) should be revised to

read that an EGF should hold a quantity of allowances for

emissions of NOx and SO2 in its compliance account by June

30 instead of May 1.

The commission agrees that allowing EGFs a period of time

to reconcile their allowance accounts is appropriate, but has

revised §116.913(a)(5) (now §116.913(a)(6)) to allow a 30-day

reconciliation period rather than the 60-day period requested by

Reliant. The commission believes that 30 days is sufficient for

reconciliation. EGFs now have until June 1 after every control

period to sell or purchase allowances in order to reconcile the

amount of allowances in their compliance account to ensure

that the number of allowances in their account are equal to, or

exceed, the amount of emissions from the prior control period.

EPA-ARD commented that §116.913(a)(6) is unclear in defining

who is responsible for submitting reports of NOx and SO2

emissions to the permits section, and that quarterly reports

may be more applicable so that sources can be evaluated each

quarter instead of all at one time. Reliant commented that the

report of annual actual emissions required by §116.913(a)(6)

shall be submitted by August 1 instead of June 1. This would

allow an additional 60 days for reconciliation. The commission

revised §116.913(a)(6), now §116.913(a)(7), to refer to owners

or operators. The commission believes that requiring reports

of trades within 30 days of the trade, and the annual report,

will provide sufficient time for a determination of compliance

with the EBTA and the EGFP. The commission has revised

§116.913(a)(7) to refer to the report required under §101.336(b),

which requires a report of the amount of emissions of each

allocated air contaminant during the preceding control period.

This will clarify the reporting requirements, since it might have

been unclear that the report under §116.913(a)(7) is the same

as the report required under §101.336(b). The commission

believes that submittal of these reports as quickly as reasonably

possible is critical to expedite the review and reconciliation of

compliance accounts to allot allowances for the next control

period. The commission believes that 60 days is a reasonable

time frame for this purpose; therefore, the rule has not been

revised to allow the reports to be submitted by August 1.

B&P commented on §116.913(a)(6) and suggested that the

word "prior" be added before "control period."

The commission agrees that §116.913(a)(6), now

§116.913(a)(7), should be revised and has added the

words "from the prior" before control period. This will clarify

that the reports that are due are those that reflect the actual

annual emissions from the previous control period.

EPA-APD noted that §116.913(a)(7) requires coal-fired EGFs to

meet opacity limitations in 30 TAC §111.111. The commenter

stated that for permitted EGFs which opt-in to the program, such

EGF must also meet a more stringent opacity limit as specified

in a permit issued by the TNRCC under Chapter 116 or issued

by EPA under 40 CFR §52.21.

The commission agrees that if an electing EGF has an opacity limitation in its existing NSR authorization, the electing EGF

must comply with the most stringent limitation. Further, the

electing EGF cannot remove any existing control technology

unless the modification is authorized under Chapter 116, Subchapter B. The rule was not revised in response to this comment; however, because §116.913 was revised for other reasons, §116.913(a)(7) is now §116.913(a)(8).

Reliant, Entergy, Group A, and CPS commented that

§116.913(a)(8) should be deleted because SB 7 does not

impose any requirement to use or not use any control technologies. Brazos Electric commented that this proposed section

would prevent an electing EGF from switching to more efficient

control technology or methodologies. Entergy commented that

SB 7 establishes severe mandatory and permissive penalties

to EGFs that exceed its allowances; thus, it is unnecessary

and redundant for the proposal to contain these permit-related

provisions. EPA-APD noted that §116.913(a)(8) does not

permit removal of existing control technology, and that the rule

should clarify whether replacement of equipment or retirement

of a part of the source should be exempt from this provision.

The commission agrees that SB 7 does not impose any

requirements regarding the use of control technology and

has deleted §116.913(a)(8). The commission believes that

a limitation of the removal of control technology is already

addressed by §116.930, concerning modifications. An electing

EGF is free to modify its facility as long as it obtains the

25 TexReg 202 January 7, 2000 Texas Register
appropriate NSR approval. Therefore, this provision has been

deleted from §116.913(a)(8).

Lloyd Gosselink commented that §116.913(b) should be

deleted, because this section fails to provide notice of what

conditions might be anticipated by the TNRCC.

The commission has not revised the rule in response to this

comment. The commission anticipates that special conditions

may be necessary, for example, to include requirements for

alternative monitoring plans or for controls that an applicant

may propose to meet allotted allowances. The commission

does not intend to use special conditions to place restrictions

on grandfathered or electing EGFs that are more restrictive that

the requirements of SB 7.

EPA-ARD commented that in §116.914(a)(1), it may be beneficial to refer to "the most current version" of 40 CFR Part 75

instead of a specific published version. This would alleviate the

need to revise the regulation whenever federal rules are revised.

In order to ensure that EGFs can locate the most current version

of state or federal regulations, the commission believes it is

appropriate to include the date that the regulation or law was

promulgated or last revised.

EPA-ARD commented that monitoring requirements in

§116.914(c) for EGFs not subject to 40 CFR Part 75 should

be identical to the monitoring requirements for EGFs that are

subject to 40 CFR Part 75 to ensure that the amount of emissions that each allowance represents will be equivalent from

one EGF to another. The commenter stated that in addition,

EGFs that volunteer to join the trading program should likewise

be required to monitor their emissions in accordance with 40

CFR Part 75 to ensure monitoring consistency and to not

allow any cost advantage due to relaxed emissions monitoring

requirements.

The commission has not revised the rule in response to this

comment. However, §116.914 was reorganized for clarity. The

prior §116.914(c) is now §116.914(b). The commission believes

that it is appropriate to continue using 40 CFR Part 75 monitoring for those EGFs already subject to the Acid Rain Program.

However, the commission does not see a basis for requiring

EGFs not subject to the Acid Rain Program to implement monitoring that is more costly and beyond the requirements of 40

CFR Part 60. 40 CFR Part 60 as currently used with EGFs

provides a sufficient level of accuracy that does not justify requiring the implementation of a new monitoring system. The

commission believes that the use of the 1.1 adjustment factor

will minimize differences in reported emissions.

EPA-ARD commented on §116.914(c) that if relative accuracies

greater than 10% are allowed, an adjustment factor of 1.1

should be applied for monitors as in the OTC NOx Budget

Program.

The commission agrees, and the proposed and adopted rule

reflect this understanding. In addition, the commission has

added the descriptive phrase "adjustment factor" in relation to

the 1.1 multiplier to §116.914(b)(2). The rule has not been

revised in response to this comment.

AE commented that it is not clear in §116.914(c) whether the

TNRCC is referring to all CEMS that exceed 10% relative

accuracy, or just CEMS that are not subject to 40 CFR 75 that

are over the 10% relative accuracy. The commenter stated that

the sentence should be changed to read: "For all CEMS not

subject to 40 CFR 75 that exceed 10% relative accuracy, actual

emissions must be determined by multiplying the CEMS data

by 1.1." However, Reliant commented that monitors on facilities

not subject to 40 CFR 75 should not be required to apply the

1.1 factor, because 40 CFR 60 does not require it and is widely

recognized and utilized by industry and regulatory agencies.

The commission agrees, and has reorganized §116.914(c), now

§116.914(b)(2), to clearly indicate that the 1.1 adjustment factor

only applies to CEMs data using a monitoring system other than

40 CFR Part 75. The 1.1 adjustment factor does not apply to

CEMs data obtained under 40 CFR Part 75 because 40 CFR

Part 75 invalidates any data with deviation greater than 10%.

To maintain consistency between 40 CFR Part 75 which

allows adjustments up to 10% relative accuracy, any alternative

monitoring including 40 CFR Part 60 will be required to apply

the 1.1 adjustment factor. 40 CFR Part 60 allows up to a 20%

relative accuracy, while 40 CFR Part 75 allows up to 10%. The

1.1 adjustment factor compensates for the 10% discrepancy.

Therefore, the rule has not been revised to remove to remove

the 1.1 adjustment factor.

EPA-ARD commented that §116.914(d) should provide standards for alternative monitoring such as what is listed under 40

CFR Part 75. EPA-APD commented that any monitoring alternatives must be approved by EPA or address why EPA approval

is not applicable in this case.

In the adopted rules, the commission moved §116.914(d) to a

new §116.914(b)(3) for purposes of clarity. The commission

believes that the majority of grandfathered and electing EGFs

are already using 40 CFR Part 75 or Part 60 monitoring,

and that the majority of grandfathered and electing EGFs

not required to monitor under 40 CFR Part 75 will rely on

40 CFR Part 60 for monitoring. If an EGF proposes a

monitoring alternative outside of 40 CFR Part 75 or Part

60, the commission will review the proposal using existing

NSR guidance for approving alternate monitoring systems.

The commission does not believe that it is necessary to

obtain EPA approval of alternative monitoring proposals. If

an EGF which is already required to use either Part 75 or

Part 60 monitoring, proposes to deviate from those programs,

EPA approval must be obtained. The commission does not

believe that many EGFs will propose alternative monitoring. In

those instances, commission staff has ample experience and

guidance to approve alternative monitoring systems. Many

permits issued by the commission provide for case-by-case

monitoring of discrete emission points or factors. These day-today decisions are not individually approved by the EPA. Since

the alternative monitoring will likely be similar to Part 75 or Part

60 monitoring, the commission should be able to review and

approve these alternative proposals. Commission decisions

concerning alternative monitoring will be subject to public notice,

since each EGFP will be subject to public notice prior to initial

issuance. Interested persons and the EPA may comment

on all the conditions of the permit including those relating to

monitoring. The alternative plan could only be implemented

after agency approval.

Reliant commented that §116.914(e)(3) should be removed

because §116.914(e) sets forth the minimum requirements to

be contained in a monitoring report. The commenter stated

that subsection (e)(3) is ambiguous in this context and should

be removed.

ADOPTED RULES January 7, 2000 25 TexReg 203
Section 116.914(e)(3), now §116.914(c), requires other information as needed; for example, periodic calibration results and

maintenance logs. This requirement for supporting information

was included to make clear that information submitted to support all monitoring protocols would need to be in sufficient detail

to satisfy staff as to its effectiveness.

On the subject of public notification of an intent to apply for a

permit, one individual stated that the commission should require

contested case hearings in addition to notice and comment

hearings. Two individuals suggested that the commission

require the use of all media in an affected area for permit notice,

and three more individuals stated that the commission should

require publication across the state. An individual stated that

the commission should require the printing of public notice in

the newspaper of largest circulation in the area of the proposed

permit and throughout the airshed.

TUC, §39.264(r) provides that applicants for EGFPs must publish notice in accordance with TCAA, §382.056. Section

382.056 outlines the procedures required of applicants for air

permits. Permits must be noticed in a newspaper of general

circulation in the municipality in which the facility is located or

in the nearest municipality. If applicable, bilingual newspaper

notice is required. In all cases, the applicant must post signs

at the facility and the permit application must be available for

review in a public place. In addition, HB 801, 76th Legislature,

revised the public notice requirements for commission permits

and provided additional opportunities for input, e.g., earlier notice to encourage public participation. In addition to the previous notice requirements, notices of intent to obtain a permit

must include information about the opportunity to be included

on mailing lists to receive updated on specific applications and

the opportunity for public meetings. Because the commission

believes that the notice requirements will provide ample information to ensure effective public participation, the rules have

not been revised.

The commission is required to provide an opportunity for a

public hearing and the submission of comment and send

notice of a decision on an application in the same manner

as provided by TCAA, §382.0561 and §382.0562. These

sections set out the requirements for public participation for

FOPs. Hearings for FOPs are not required to be conducted

under the APA. Since EGFPs are to be issued using the same

process as that for FOPs, hearings for EGFPs are also not

required to be held under the contested case provisions of

the APA. The commission does not believe it is necessary to

hold two different types of hearings for EGFPs. If any facility

authorized by an EGFP is modified, as that term is defined

for state or federal purposes, the facility is required to obtain

appropriate authorization under Chapter 116, Subchapter B.

That modification would be subject to public notice and an

opportunity to request a contested case hearing. The rules

have not been changed in response to the comment.

One individual commented that the rules do not allow sufficient

time for public comment on individual permits. The individual

objected having to raise all issues by the end of the public comment period, and opposed the commission’s not allowing incorporation by reference of hearing material, since this causes

increased copying costs for citizens, discourages public participation, and wastes natural resources. The individual objected

to the terms "reasonable" and "unreasonable" that the commission proposed in the evaluation of hearing requests.

The adopted rules allow 30 days for the submission of public

comment and, if a hearing is requested and held, the comment

period automatically extends to the end of the hearing. A 30-day

comment period is used for all air permits, except renewals and

concrete batch plants, that are subject to public notice and, in

the experience of the commission, that time period has proved

to be sufficient for interested persons to submit comments on

permits. Further, TUC, §39.264 directs the commission to

provide notice consistent with the requirements of the TCAA

which requires a 30-day public comment period. In order for

the commission to respond to comments in a timely manner, it

is important for all comments to be submitted within a specified

time period. This ensures that all comments are considered

at the same time. The rules do not prohibit incorporation

by reference of existing documents. Rather, they provide

criteria that ensures that the documents supporting comments

on permits are easily obtained and verifiable, since these

documents will be included in the public record concerning an

EGFP application.

Since TUC, §39.264 requires that public notice and opportunity

for a hearing be done in the same manner as for FOPs, the

commission is not required to hold a hearing if the basis of

a request by a person who may be affected is determined to

be unreasonable. Thus, reasonableness is the standard by

which the commission must evaluate a hearing request on an

EGFP. The commission believes that "reasonable" is a term

that is circumstantial, but with a common understanding. The

reasonableness of each request must be considered in light of

the particular permit, the application, and the arguments raised

by the protestant. For example, a hearing request based on

water concerns would not be a reasonable basis for a hearing

on an EGFP. Similarly, emissions from non-EGFs at a site

would not be relevant to the issuance of an EGFP. Because

reasonableness is very case-specific, the commission does not

believe that it is appropriate to revise the rule in response to

this comment.

AE commented that the term "APA" is not defined in

§116.920(c).

The rule has not been revised in response to this comment.

Section 3.2 of 30 TAC Chapter 3, Definitions, defines the

Texas Administrative Procedure Act, Texas Government Code,

Chapter 2001 and abbreviates this term as "APA." Section

3.1, Applicability, provides that words and terms, when listed

in Chapter 3 and used in commission rules, shall have the

meanings in that chapter, unless the context clearly indicates

otherwise. However, a definition in Chapter 3 shall not apply

to another chapter of the commission rules if the word or term

is defined in that chapter. Since Chapter 116 does not define

"APA" differently from the definition in Chapter 3, the term does

not need further definition.

NFN commented on §116.920, that the publication of notice

of permit hearing should not only be published in the local

area, but also in the largest nearby metropolitan areas that

might be affected. LWV-TX commented that the rules should

require public notice in all news media in all affected areas,

not just in the local newspaper. This will give citizens every

opportunity for meaningful input into the permitting process. PC

urged the commission to require real notice of public hearings

to press in all affected areas, not just in the nearest municipality.

The commenter stated that the rules only require that the local

newspaper be notified, but surely this type of information could

be given by the TNRCC to newspapers in communities affected

25 TexReg 204 January 7, 2000 Texas Register
by transportation and also made available on the website. One

individual commented that the rules should require more public

notice beyond a small ad in a newspaper and urged the use of

community newspapers in addition to large newspapers in large

cities. PC commented that public notice should be given in the

municipality adjacent to a plant due to the fact that there are

people who are affected who live upwind or downwind and are

affected by transport of emissions from power plants.

The rule has not been revised in response to these comments.

TUC, §39.264(r) requires applicants for EGFPs to publish notice

of intent to obtain a permit in accordance with TCAA, §382.056,

which outlines the procedures required of applicants for air

permits. Permits must be noticed in a newspaper of general

circulation in the municipality in which the facility is located

or the nearest municipality. If applicable, bilingual notice is

required. In all cases, applicants must post signs at the facility.

HB 801 revised the public notice requirements for commission

permits. In addition to the previous notice requirements, notices

of intent to obtain a permit must include information about the

opportunity to be included on mailing lists to receive updates

on specific applications and the opportunity for public hearings.

The commission is required to provide an opportunity for public

hearing and for the submission of public comment and to send

notice of a decision on the application in the same manner as

provided by TCAA, §382.0561 and §382.0562, which are the

hearing and notice requirements for FOPs. The commission

believes that these procedures adequately notify persons who

may be affected by emissions from EGFs. The adopted rule

requires that notice be provided in the nearest municipality if no

newspaper of general circulation is available in the municipality

where the EGF is located. Since the commission is proposing

additional SIP rules intended to address the issue of transport,

the opportunity to comment on transport issues will occur during

the public comment period on those rules instead of during

the consideration of individual EGFPs. The rule has not been

revised in response to this comment.

Reliant commented that §116.921(a) should be revised to require public notice only for grandfathered EGFs and not for

electing EGFs, since they have already undergone public review for their existing permit.

The commission revised the provisions in Subchapter I, concerning the inclusion of NSR permits for electing EGFs in an

EGFP. Because the NSR permit will now only be altered to include a reference to the EGFP, the provision in §116.920(c),

concerning public notice, is no longer necessary. Only the

EGFP will be subject to public notice and if necessary, it will

include provisions from the NSR permit. The NSR permit itself

will not be subject to public notice.

EPA-APD noted that under §116.921(a), the notice and comment hearing requirements only apply to the initial issuance of

an EGFP. The commenter stated that the TNRCC should address why it is not requiring notice and comment hearing for

subsequent revisions to the EGFP.

The rule has not been revised in response to this comment.

Section 116.930 provides that modifications to EGFs must comply with Chapter 116, Subchapter B. Therefore, any modification

to an EGF would have to be done under existing NSR permitting

procedures. The NSR procedures utilize contested case hearings and not notice and comment hearings. Since §116.921 is

specifically for initial issuance and §116.930 is for modifications

to EGFs, the commission does not believe it is necessary to

revise §116.921(a).

EPA-APD commented that §116.921(b) should define what is

a "reasonable" or "unreasonable" request for hearing, and that

if these terms are defined elsewhere in the regulations or in

the statute, a cross-reference to the applicable definition or

provision of the regulation or statute would be helpful.

TUC, §39.264(r) requires applicants for EGFPs to publish notice

of intent to obtain a permit in accordance with TCAA, §382.056.

The commission is required to provide an opportunity for public

hearing, for the submission of public comment, and to send

notice of a decision on the application in the same manner as

provided by TCAA, §382.0561 and §382.0562, which are the

hearing and notice requirements for FOPs. TCAA, §382.0561

provides that the commission is not required to hold a hearing

if the basis of the request by a person who may be affected

is determined to be unreasonable. Therefore, reasonableness

is the standard by which the commission must evaluate the

basis of a hearing request. The commission believes that

"reasonable" is a term that is circumstantial, and that the

reasonableness of each request must be considered in light of

the particular permit, the application, and the arguments raised

by the protestant. For example, a hearing request based on

water concerns would not be a reasonable basis for a hearing

on an EGFP. Similarly, emissions from non-EGFs at a site

would not be relevant to the issuance of an EGFP. Because

reasonableness is very case-specific, the commission does not

believe that it is appropriate to revise the rule in response to

this comment.

AE commented that §116.921(e) states that a written transcript

or tape recording must be made available to the public without

stating which entity is responsible for providing this.

Because the hearings for EGFPs are notice and comment hearings, the commission does not anticipate using court reporters

to create transcripts for the hearings. Commission staff will

oversee each hearing and will create an audio recording of the

proceedings. Copies of this tape can be obtained from the

commission upon request. The commission will charge a reasonable fee to cover the cost of coping, the cost of the tape,

and the transcription of the tape.

Reliant commented that §116.930 should be deleted or should

clarify that other permitting options are available.

Section 116.930 provides that modifications to EGFs must comply with Chapter 116, Subchapter B. Subchapter B allows modifications under other chapters or subchapters, as appropriate.

Therefore, any modification to an EGF would have to be done

under NSR permitting procedures. The commission believes

that this section is necessary to ensure that permit holders are

aware of the process to modify EGFs and has not deleted the

section in the adopted rule.

Subchapter A. DEFINITIONS

30 TAC §116.18

STATUTORY AUTHORITY

The new sections are adopted under TUC, §39.264, which authorizes the commission to develop rules for the permitting of

electric generating facilities; and Texas Health and Safety Code,

TCAA, §382.011, which authorizes the commission to administer the requirements of the TCAA; §382.012, which provides

the commission the authority to develop a comprehensive plan

ADOPTED RULES January 7, 2000 25 TexReg 205
for the state’s air; §382.017, which authorizes the commission

to adopt rules consistent with the policy and purposes of the

TCAA; §382.051, which authorizes the commission to issue

permits; §382.0513, which authorizes the commission to establish and enforce permit conditions consistent with the TCAA;

§382.0515, which requires applicants to provide information that

assures compliance with state and federal laws and regulations;

§382.0518, which authorizes the commission to issue permits

for new construction and modifications; §382.0519, which authorizes the commission to issue voluntary emission reduction

permits, §382.05191, which authorizes public notice for voluntary emission reduction permits; §382.05193, which authorizes

permits through emissions reductions, §382.055, which authorizes the commission to establish procedures for review or renewal of a permit; §382.056, which authorizes the commission

to require public notice of certain permit applications and procedures for requesting hearings and responding to comments;

§382.0561, which authorizes hearing procedures for FOPs;

§382.0562, which requires notices of decision; and §382.061,

which authorizes the commission to delegate permitting authority to the executive director; and Texas Water Code, §5.122,

which authorizes the commission to delegate uncontested matters to the executive director.

§116.18. Electric Generating Facility Permits Definitions.

The following words and terms, when used in Subchapter I of

this chapter (relating to Electric Generating Facility Permits) shall

have the following meanings, unless the context clearly indicates

otherwise.

(1) Allowance - As defined in §101.330(1) of this title

(relating to Definitions).

(2) Capacity factor - Either:

(A) the ratio of an electric generating facility’s (EGF)

actual annual electric output (expressed in megawatt-hours) to the

EGF’s nameplate capacity times 8,760 hours; or

(B) the ratio of an EGF’s annual heat input (in

millions of British thermal units (MMBtu)) to the EGF’s maximum

design heat input (in MMBtu per hour) times 8,760 hours.

(3) Coal - As defined in §101.330(6) of this title.

(4) Coal-fired - As defined in §101.330(7) of this title.

(5) Compliance account - As defined in §101.330(8) of

this title.

(6) Control period - As defined in §101.330(9) of this

title.

(7) Electing EGF - As defined in §101.330(11) of this

title.

(8) Electric generating facility (EGF) - As defined in

§101.330(12) of this title.

(9) Grandfathered EGF - As defined in §101.330(14) of

this title.

(10) Nameplate capacity - The maximum electrical

output (expressed in megawatts) that an EGF can sustain over a

specified period of time when not restricted by seasonal or other

deratings.

(11) Peaking unit - An EGF that has:

(A) an average capacity factor of no more than 10%

during the past three calendar years; and

(B) a capacity factor of no more than 20% in each of

those calendar years.

(12) Person - As defined in §101.330(17) of this title.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 22,

1999.

TRD-9909015

Margaret Hoffman

Director, Environmental Law Division

Texas Natural Resource Conservation Commission

Effective date: January 11, 2000

Proposal publication date: September 10, 1999

For further information, please call: (512) 239-1966

♦♦♦

Subchapter I. ELECTRIC GENERATING FACILITY PERMITS

30 TAC §§116.910 - 116.914, 116.916, 116.920 - 116.922,

116.930, 116.931

STATUTORY AUTHORITY

The new sections are adopted under Texas Utilities Code,

§39.264, which authorizes the commission to develop rules for

the permitting of electric generating facilities; and Texas Health

and Safety Code, Texas Clean Air Act (TCAA), §382.012, which

provides the commission the authority to develop a comprehensive plan for the state’s air; §382.017, which authorizes the

commission to adopt rules consistent with the policy and purposes of the TCAA; §382.0513, which authorizes the commission to establish and enforce permit conditions consistent with

the TCAA; §382.051, which authorizes the commission to issue permits; §382.0518, which authorizes the commission to issue permits for new construction and modifications; §382.0519,

which authorizes the commission to issue voluntary emission

reduction permits, §382.05191, which authorizes public notice

for voluntary emission reduction permits; §382.05193, which

authorizes permits through emissions reductions, §382.055,

which authorizes the commission to establish procedures for

review or renewal of a permit; §382.056, which authorizes the

commission to require public notice of certain permit applications and procedures for requesting hearings and responding

to comments; §382.0561, which authorizes hearing procedures

for FOPs; §382.0562, which requires notices of decision; and

§382.061, which authorizes the commission to delegate permitting authority to the executive director; and Texas Water Code,

§5.122, which authorizes the commission to delegate uncontested matters to the executive director.

§116.910. Applicability.

(a) The owner or operator of a grandfathered electric

generating facility (EGF) shall apply for a permit to operate that

facility under this subchapter.

(b) Owners or operators of electing EGFs opting to obtain

allowances under Chapter 101, Subchapter H, Division 2 of this

title (relating to Emissions Banking and Trading of Allowances),

shall submit a request to alter any related existing New Source

Review (NSR) permits at the time of application for a permit under

subsection (a) of this section. Alterations must be consistent with

25 TexReg 206 January 7, 2000 Texas Register
the requirements of §116.116(c) of this title (relating to Changes to

Facilities).

(c) The owner, or the operator who is authorized to act for

the owner, of a grandfathered or electing EGF is responsible for

complying with this subchapter.

(d) A municipal corporation, electric cooperative, or river

authority may exclude any EGF with a nameplate capacity of 25

megawatts or less from this subchapter. The municipal corporation,

electric cooperative, or river authority must notify the commission by

January 1, 2000, of its intent to exclude those EGFs. If the municipal

corporation, electric cooperative, or river authority reevaluates its

intent to exclude EGFs, it may choose to permit any of those EGFs

consistent with the requirements of this subchapter.

(e) Emissions of nitrogen oxides shall be permitted under

this subchapter for any grandfathered or electing EGF. Emissions

of sulfur dioxide and particulate matter shall be permitted under

this subchapter only for grandfathered or electing coal-fired EGFs.

Emissions of other air contaminants from grandfathered EGFs may

be permitted under this subchapter, provided the grandfathered EGFs

meet the requirements of Chapter 116, Subchapter H of this title

(relating to Voluntary Emission Reduction Permits).

(f) Owners or operators of grandfathered facilities as defined

in §116.10 of this title (relating to General Definitions) at sites

with grandfathered or electing EGFs subject to this subchapter may

consolidate any permit issued under Chapter 116, Subchapter H of

this title with a permit issued under this subchapter.

(g) An EGF that generates electric energy primarily for internal use but that during 1997 sold, to a utility power distribution

system, less than one-third of its potential electrical output capacity,

or less than 219,000 megawatt-hours, is not subject to the requirements of this chapter.

§116.911. Electric Generating Facility Permit Application.

(a) Owners or operators of grandfathered or electing electric

generating facilities (EGF) shall submit an application to authorize

nitrogen oxides (NOx

) emissions and, if applicable, sulfur dioxide

(SO2

) and particulate matter (PM) emissions. The application must

include a completed Form PI-1-U, General Application. The Form PI1-U must be signed by an authorized representative of the applicant.

The Form PI-1-U specifies additional support information which

must be provided before the application is deemed complete. In

order to be granted an electric generating facility permit (EGFP), the

owner or operator shall submit information to the commission which

demonstrates that all of the following are met.

(1) Measurement of emissions and performance demonstration. Applicants must propose monitoring and reporting for the

measurement of emissions and demonstration of performance consistent with §116.914 of this title (relating to Emissions Monitoring and

Reporting Requirements).

(2) Control method. New control methods proposed

in initial applications must comply with the requirements in

§116.617(1), (3), (4)(A) and (B) and (5) - (9) of this title (relating

to Standard Permit for Pollution Control Projects).

(3) Air dispersion modeling or ambient monitoring for

pollution control projects. Computerized air dispersion modeling

and/or ambient monitoring may be required by the commission’s Air

Permits Division where there is an increase in emissions to determine

the air quality impacts from controls proposed under paragraph (2)

of this subsection.

(4) Opacity limitations for coal-fired grandfathered and

electing EGFs. The coal-fired grandfathered and electing EGFs must

meet the opacity limitations of §111.111 of this title (relating to

Requirements for Specified Sources).

(b) Application information for electing EGFs.

(1) In addition to the information required in this

section, EGFP applications regarding electing EGFs shall contain the

following information:

(A) documentation of the emissions from the 1997

Emissions Scorecard from the EPA Acid Rain Program, or if that

information is not available, the actual emissions from that electing

EGF for calendar year 1997;

(B) documentation of fuel consumption, fuel heating

values, and heat input in millions of British thermal units (MMBtu)

for calendar year 1997;

(C) identification of the electing EGFs to be included.

(2) Emissions of air contaminants from electing EGFs

other than NOx

, and if applicable, SO2 and PM, already authorized

by Chapter 116 of this title (relating to Control of Air Pollution by

Permits for New Construction or Modification), will not be authorized

under this subchapter.

(c) The owner or operator of a grandfathered or electing

EGF must submit an application for a permit under this subchapter

on or before September 1, 2000.

(d) All applications for an EGFP shall be submitted under

the seal of a Texas licensed professional engineer if required by

§116.110(e) of this title (relating to Applicability).

§116.912. Electing Electric Generating Facilities.

An electing electric generating facility (EGF) may opt out of the

requirements of this subchapter under the following conditions.

(1) The electing EGF must notify the commission of its

intent to opt out prior to the beginning of the next control period.

The decision to opt out of the requirements of this subchapter will

become effective at the beginning of the control period that follows

notification to the commission.

(2) The electing EGF may not opt out during a control

period.

(3) Once the electing EGF has opted out, all of the

following apply:

(A) all allowances for the electing EGF will be voided

by the commission and may not be banked for subsequent use;

(B) no allowances will be allocated for subsequent

control periods;

(C) the electing EGF may not participate in the

emissions banking and trading of allowances at any future date;

(D) the owner or operator shall request an alteration

to the existing New Source Review permit to remove the conditions

referencing the electric generating facility permit.

§116.913. General and Special Conditions.

(a) The following general conditions shall be applicable to

every electric generating facility permit (EGFP) unless otherwise

specified in the permit.

(1) A permit issued under this subchapter authorizes the

following:

ADOPTED RULES January 7, 2000 25 TexReg 207
(A) nitrogen oxides (NOx

) emissions from all grandfathered and electing electric generating facilities (EGF);

(B) sulfur dioxides (SO2

) emissions from coal-fired

grandfathered and electing EGFs.

(C) particulate matter through opacity limitations as

specified in §111.111 of this title (relating to Requirements for

Specified Sources) for coal-fired grandfathered and electing EGFs.

(2) An EGFP may permit emissions of all other air

contaminants from grandfathered EGFs, provided the requirements

of Chapter 116, Subchapter H of this title (relating to Voluntary

Emissions Reduction Permits) are met.

(3) Grandfathered facilities as defined in §116.10 of this

title (relating to General Definitions) at sites with grandfathered or

electing EGFs and permitted under Chapter 116, Subchapter H of this

title may be consolidated with a permit issued under this subchapter.

(4) The grandfathered or electing EGF must comply with

Chapter 101, Subchapter H, Division 2 of this title (relating to Emissions Banking and Trading of Allowances) including the requirement

to maintain allowances in a compliance account. Allowances may

be transferred in accordance with §101.335 of this title (relating to

Allowance Banking).

(5) Mass emission monitoring and reporting shall be

conducted in accordance with §116.914 of this title (relating to

Emissions Monitoring and Reporting Requirements).

(6) On June 1 after every control period, a grandfathered

or electing EGF subject to this subchapter shall hold a quantity of

allowances for emissions of NOx and, where applicable, SO2

, in its

compliance account that is equal to or greater than the total emissions

of that air contaminant emitted during the prior control period.

(7) Owners or operators shall submit a report of the

amount of emissions of each allocated air contaminant, from the

prior control period to the Air Permits Division consistent with

the requirements of §101.336(b) of this title (relating to Emission

Monitoring, Compliance Demonstration, and Reporting).

(8) Coal-fired grandfathered and electing EGFs must

meet the opacity limitations of §111.111 of this title (relating to Requirements for Specified Sources).

(b) Special conditions may be included in the EGFP.

§116.914. Emissions Monitoring and Reporting Requirements.

(a) Grandfathered or electing electric generating facilities

(EGF) subject to 40 Code of Federal Regulations Part 75, effective

June 25, 1999 (40 CFR Part 75) shall do the following.

(1) For grandfathered or electing EGFs subject to the

requirements of 40 CFR Part 75, concerning Continuous Emission

Monitoring, all monitoring systems must comply with the initial

performance testing and periodic calibration, accuracy testing, and

quality assurance/quality control testing specified in 40 CFR Part 75.

(2) For grandfathered and electing EGFs subject to 40

CFR Part 75, a certified monitoring system under 40 CFR Part 75

shall be used to demonstrate compliance with this subchapter.

(A) If the grandfathered or electing EGF has a

flow monitor certified under 40 CFR Part 75, nitrogen oxides

(NOx

) emissions in pounds per hour shall be determined using a

NOx continuous emission monitoring system (CEMS) and the flow

monitor.

(B) If the grandfathered or electing EGF does not have

a certified flow monitor, but does have a NOx CEMS, NOx emissions

in pounds per hour shall be determined by multiplying pounds of

NOx per million British thermal units (lbs/MMBtu) times heat input

in MMBtu per hour (MMBtu/hr). The procedures in 40 CFR Part

75, Appendix F, concerning Conversion Procedures, Section 3, shall

be used to convert the measured concentration of NOx and a diluent

(carbon dioxide (CO2

) or oxygen (O2)) into an emission rate in lbs/

MMBtu. The procedures in 40 CFR Part 75, Appendix F, Section 5,

shall be used to determine the hourly heat input in MMBtu/hr. These

two values (lbs/MMBtu and MMBtu/hr) shall be multiplied together

to determine NOx emissions in lbs/hr.

(C) The procedures in 40 CFR Part 75, Appendix E,

concerning Optional NOx Emissions Estimation Protocol for Gas-fired

Peaking Units and Oil-fired Peaking Units, may be used to estimate

the NOx emission rate.

(b) Grandfathered or electing EGFs not subject to 40 CFR

Part 75 shall comply with:

(1) the initial performance testing and periodic calibration, accuracy testing, and quality assurance/quality control testing

specified in 40 CFR Part 75; or

(2) those same requirements in 40 CFR Part 60, concerning New Source Performance Standards (40 CFR Part 60). Actual

emissions must be determined by multiplying the CEMs data by an

adjustment factor of 1.1 for all grandfathered and electing EGFs not

using a 40 CFR Part 75 monitoring system if the CEMs exceeds 10%

relative accuracy.

(3) in lieu of the monitoring required by paragraph (1) or

(2) of this subsection, the electric generating facility permit (EGFP)

may authorize alternative monitoring to calculate mass emissions

under this section. The applicant must submit the following for review

of an alternative monitoring proposal:

(A) a description of the monitoring approach to be

used;

(B) a description of the major components of the

monitoring system, including the manufacturer, serial number of

the component, the measurement span of the component, and

documentation to demonstrate that the measurement span of each

component is appropriate to measure all of the expected values;

(C) an estimate of the accuracy of the system and

documentation to demonstrate how the estimate of accuracy was

determined;

(D) a description of the tests that will be used

for initial certification, initial quality assurance, periodic quality

assurance, and relative accuracy; and

(E) additional information may be requested before

approving a request for alternative monitoring. Alternative monitoring shall be incorporated into the EGFP.

(4) emissions in pounds per hour shall be determined

using the NOx

CEMS and one of the following methods.

(A) The owner or operator may elect to comply with

subsection (a)(2)(A) or (B) of this section.

(B) The grandfathered or electing EGF may use a

flow monitor certified under 40 CFR Part 60 to determine emissions

in pounds per hour.

(C) NOx emissions in pounds per hour may be

determined by multiplying the lbs/MMBtu times the heat input in

25 TexReg 208 January 7, 2000 Texas Register
MMBtu/hr. The procedures in 40 CFR Part 60, Appendix A, Method

19 shall be used to convert the measured concentration of NOx

and a diluent (CO2 or O2) into emission rates in lbs/MMBtu. The

procedures in 40 CFR Part 75, Section 5, Appendix F shall be used

to determine the hourly heat input in MMBtu/hr. These two values

(lbs/MMBtu and MMBtu/hr) shall be multiplied together to determine

NOx emissions in lbs/hr;

(5) for grandfathered and electing EGFs with a heat input

of less than 100 MMBtu/hr and for peaking units emissions in pounds

per hour, may be determined using the procedures in Appendix E of

40 CFR Part 75 to estimate the emission rate.

(c) The following requirements apply to all grandfathered

and electing EGFs.

(1) During a period when valid data is not being recorded

by monitoring devices approved for use to demonstrate compliance

with this subchapter, missing or invalid data shall be replaced with

representative default data in accordance with the provisions of 40

CFR Part 75, Subpart D, concerning Missing Data Substitution

Procedures.

(2) Data collected from monitoring of grandfathered and

electing EGFs shall be used to calculate the actual emissions over a

control period. The information in this report shall be submitted by

June 30 of each year and may be submitted with the report required

under §101.336(b) of this title (relating to Emission Monitoring,

Compliance Demonstration, and Reporting). At a minimum, the

report shall contain the following information:

(A) a description of the monitoring protocol;

(B) a completed Form AR-1, Emissions Monitoring

Data Form;

(C) other information as necessary to validate the

actual emissions during the prior control period, including, but not

limited to, periodic calibration results and maintenance logs.

§116.916. Permits for Grandfathered and Electing Electric Generating Facilities in El Paso County.

Grandfathered and electing electric generating facilities in El Paso

County are not required to meet nitrogen oxides allowance requirements if the commission or EPA determines that reductions in nitrogen oxides emissions in the El Paso Region otherwise required by

this subchapter would result in increased ambient ozone levels in El

Paso County.

§116.920. Public Participation for Initial Issuance.

(a) An applicant for an electric generating facility permit

(EGFP) shall publish notice of intent to obtain the permit in

accordance with Chapter 39 of this title (relating to Public Notice).

(b) Public notice for an EGFP may be combined with

the public notice for a voluntary emission reduction permit, under

Chapter 116, Subchapter H of this title (relating to Voluntary

Emission Reduction Permits).

(c) Any person who may be affected by emissions from a

grandfathered or electing EGF may request the commission to hold

a notice and comment hearing on the EGFP application. The public

comment period shall end 30 days after the publication of Notice of

Receipt of Application and Intent to Obtain Permit under §39.418 of

this title (relating to Notice of Receipt of Application and Intent to

Obtain Permit). Any hearing request must be made in writing during

the 30-day public comment period.

(d) Any hearing regarding initial issuance of an EGFP shall

be conducted under the procedures in §116.921 of this title (relating

to Notice and Comment Hearings for Initial Issuance) and not under

the APA.

(e) Responses to public comments and the notice of the

commission’s decision to issue or deny an EGFP shall be conducted

under the procedures in §116.922 of this title (relating to Notice of

Final Action).

(f) A person affected by a decision to issue or deny an

EGFP may move for rehearing under the appropriate procedure in

Chapter 50 of this title (relating to Action on Applications and Other

Authorizations) and may seek judicial review under TCAA, §382.032

(relating to Appeal of Commission Action).

§116.921. Notice and Comment Hearings for Initial Issuance.

(a) The notice and comment hearing requirements apply only

to the initial issuance of a electric generating facility permit (EGFP).

(b) The commission shall decide whether to hold a hearing.

The commission is not required to hold a hearing if the basis of

the request by a person who may be affected by emissions from

a grandfathered or electing electric generating facility (EGF) is

determined to be unreasonable. If a hearing is requested by a person

who may be affected by emissions from a grandfathered or electing

EGF, and that request is reasonable, the commission shall hold a

hearing.

(c) At the applicant’s expense, notice of a hearing on a draft

EGFP must be published in the public notice section of one issue

of a newspaper of general circulation in the municipality in which

the grandfathered or electing EGF is located, or in the municipality

nearest to the location of the grandfathered or electing EGF. The

notice must be published at least 30 days before the date set for the

hearing. The notice must include the following:

(1) the time, place, and nature of the hearing;

(2) a brief description of the purpose of the hearing; and

(3) the name and phone number of the commission office

to be contacted to verify that a hearing will be held.

(d) Any person, including the applicant, may submit oral or

written statements and data concerning the draft EGFP.

(1) Reasonable time limits may be set for oral statements,

and the submission of statements in writing may be required.

(2) The period for submitting written comments is

automatically extended to the close of any hearing.

(3) At the hearing, the period for submitting written

comments may be extended beyond the close of the hearing.

(e) A tape recording or written transcript of the hearing must

be made available to the public.

(f) Any person, including the applicant, who believes

that any condition of the draft EGFP is inappropriate or that the

preliminary decision to issue or deny the permit is inappropriate, shall

raise all issues and submit all arguments supporting that position by

the end of the public comment period.

(g) Any supporting materials for comments submitted under

subsection (f) of this section must be included in full and may not

be incorporated by reference, unless the materials are one of the

following:

(1) already part of the administrative record in the same

proceedings;

(2) state or federal statutes and regulations;

ADOPTED RULES January 7, 2000 25 TexReg 209
(3) EPA documents of general applicability; or

(4) other generally available reference materials.

(h) The commission shall keep a record of all comments

received and issues raised in the hearing. This record is available to

the public.

(i) The draft EGFP may be changed based on comments

pertaining to whether the permit provides for compliance with the

requirements of this subchapter.

(j) The commission shall respond to comments consistent

with §116.922 of this title (relating to Notice of Final Action).

§116.922. Notice of Final Action.

(a) After the public comment period or the conclusion of

any notice and comment hearing, the commission shall send notice

by first-class mail of the final action on the application to any person

who commented during the public comment period or at the hearing,

and to the applicant.

(b) The notice must include the following:

(1) the response to any comments submitted during the

public comment period;

(2) identification of any change in the conditions of the

draft electric generating facility permit and the reasons for the change;

(3) a statement that any person affected by the decision

of the commission may petition for rehearing under the appropriate

procedure in Chapter 50 of this title (relating to Action on Applications and Other Authorizations) and may seek judicial review under

TCAA, §382.032 (relating to Appeal of Commission Action).

§116.931. Renewal.

Electric generating facility permits shall be renewed in accordance

with Chapter 116, Subchapter D of this title (relating to Permit

Renewals).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 22,

1999.

TRD-9909016

Margaret Hoffman

Director, Environmental Law Division

Texas Natural Resource Conservation Commission

Effective date: January 11, 2000

Proposal publication date: September 10, 1999

For further information, please call: (512) 239-1966

♦♦♦

TITLE 31. NATURAL RESOURCES AND

CONSERVATION

Part 4. SCHOOL LAND BOARD

Chapter 155. LAND RESOURCES

Subchapter A. COASTAL PUBLIC LANDS

31 TAC §155.4

The School Land Board (Board) adopts an amendment to

§155.4, relating to Permits without changes to the proposed

text as published in the October 15, 1999, issue of the Texas

Register (24 TexReg 8918). The text of the rule will not be

republished.

The rule adds derelict and dilapidated structures to the criteria

used by the Board to determine which structures to permit.

The adoption of the rule to add derelict and dilapidated structures to the criteria used by the Board to grant or deny permits

is subject to the Texas Coastal Management Program (CMP),

§505.11(a)(1)(H) of this title, relating to Actions and Rules Subject to the Coastal Management Program, and must be consistent with the applicable CMP goals and policies under §501.14(i)

of this title, relating to Policies for Specific Activities and Coastal

Natural Resource Areas. The General Land Office (Land Office) has reviewed this proposed action for consistency with the

CMP goals and policies in accordance with the regulations of

the Coastal Coordination Council (Council). The proposed action is consistent with the coastal public lands regulations which

the Council has determined to be consistent with the CMP. Consequently, the Land Office has determined that the proposed

action is consistent with the applicable CMP goals.

No comments were received regarding the adoption of the

proposed amendment to this rule.

The Land Office has prepared a takings impact assessment for

the adoption of this rule and has determined that adoption of

this rule will not result in a taking of private property. To receive

a copy of the takings impact assessment, please send a written

request to Ms. Melinda Tracy, Texas Register Liaison, General

Land Office, 1700 North Congress Avenue, Room 626, Austin,

Texas 78701-1495, facsimile number (512) 463-6311.

This rule is adopted under Texas Natural Resources Code

Chapter 33, §33.064 which authorizes the Board to adopt procedural and substantive rules necessary for the management

of coastal public lands.

Texas Natural Resources Code §33.119 is affected by this rule.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the

agency’s legal authority.

Filed with the Office of the Secretary of State on December 20,

1999.

TRD-9908897

Larry R. Soward

Chief Clerk

General Land Office

Effective date: January 9, 2000

Proposal publication date: October 15, 1999

For further information, please call: (512) 305-9129

♦♦♦

TITLE 34. PUBLIC FINANCE

Part 1. COMPTROLLER OF PUBLIC

ACCOUNTS

Chapter 9. PROPERTY TAX ADMINISTRATION

25 TexReg 210 January 7, 2000 Texas Register