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: ....**,I-:~**

... :0..._

(.:-,**"-~.:.: ;-T~**  :::-



# - 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

of Senate Bill 7, 76 th 

## 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, 76 th 

## Legislature, 1999.

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

are also enclosed. I look forward to your expeditious approval of these 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 10 1 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 assessmentfor 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 RegisterDeductions; §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 regionsof the state. As stated in TUC, §39.264(c), the Legislature intended that total annual emissions of nitrogen oxides (NO

x) from grandfathered EGFs would not exceed 50% of the emissions during 1997 as reported to the commission, and additionally forcoal-fired grandfathered EGFs, total annual emissions of sulfur dioxide (SO

2) 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 NewSource Review Permits, may elect to participate in the permitting program adopted concurrently in Chapter 116, SubchapterI. 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 Chapter116, 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, regardlessof 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 NO

x or SO

2 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 andnot 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 beused 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 129fuel (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 periodbeginning 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-35and west of IH-37 are not included in this region. The commission believes that had the Legislature intended for the definitionto 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 beconsistent with current commission planning structures. "Electric generating facility" means a facility that generates electric energy for compensation and is owned or operated by a personin 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 ANALYSISOF TESTIMONY portion of this preamble. The "El Paso Region" is now defined to include all of El Paso County, CiudadJuarez, 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, orriver authority. The commission originally modified this definition to exclude a facility that generates electric energy primarilyfor 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 removedand 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 atan EGF. Heat input does not include the heat derived from reheated combustion air, recirculated flue gas, or exhaust from other sources. The definition of "NO

x" was revised in response to comments. "NO

x allowance" is an authorization to emit NO

x, 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 ruleas to whether "permitting" was referencing a permit under Chapter 116, Subchapter B, Subchapter H, or Subchapter I. The ruleswere 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 forthe 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. "SO

2 allowance" is an authorization to emit SO

2 , 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 NO

x allowance nor an SO

2 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 RegisterBritish 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 NO

x emissions, and for coal-fired EGFs, 25% reduction in SO

2 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 requirementsof 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 NO

x per MMBtu and 1.38 pounds of SO

2 perMMBtu. The emission rate in the West Texas and El Paso Regions is 0.195 pounds of NO

x per MMBtu. Consistent with TUC, §39.264(i)(2), the allowances for electing EGFs are equal to theEGF’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 SO

2 from 1997 would be used to establish its allowances.

In addition to the 50% reduction expected from grandfatheredEGFs 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. Forthe 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 NO

x or SO

2 , 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) specifiesthat allowances may only be used for the current or subse

## ADOPTED RULES January 7, 2000 25 TexReg 131quent 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 onlybe 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 thetrade. The new §101.335(c) specifies that trades are prohibited prior to May 1, 2003. The new §101.335(d) specifies thattraded 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 betransferred 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 NO

x, 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 NO

x 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 andReporting 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 NO

x will increase ambient levels of ozone. Currently, NO

x reductions are not required for facilities in the El Paso nonattainment area because EPA has granted a waiver under FCAA, §182(f), concerning NO

x Requirements. Under this waiver, NO

x reductions are not required if the attainment demonstration for compliance with the ozone NAAQS can be made without a NO

x 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 NO

x 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 NO

x 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 Registerto 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 NO

x by 50% and, if applicable, SO

2 , 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 NO

x and SO

2 . The action significantly advances this purpose by requiring substantial reductions in the emission of NO

x and SO

2 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 relatesto 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 andrules 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 emissionallowances and the banking and trading of allowances, the commission has determined that the rules are consistent with theapplicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal naturalresource 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 NO

x and SO

2 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 closedon 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); SouthwesternPublic 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 ofTexas (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 EconomicDevelopment 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 reductionsshould be permanent. Three individuals stated that the commission should enforce reduced emissions from grandfathered electric generating facilities, and two more individuals addedthat 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 NO

x 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 SO

2 , particularly to improve visibility in Big Bend. Another individual added that the commission must require a larger NO

x and SO

2 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 theBig 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 SO

2 as needed. As stated previously, the commission is addressing additional NO

x 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 SO

2 , 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 acap and trade or banking system because it avoids environ

## ADOPTED RULES January 7, 2000 25 TexReg 133mental justice issues and perpetuates emissions in low-income areas. The same individual suggested that the exclusion forindividual 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 NO

x from grandfathered EGFs will not exceed 50% of the NO

x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO

2 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 NO

x and a 25% reduction in SO

2 within the region. SB 7 does notrequire 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 poweror 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 tomeet 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 commissionheld 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 wereposted 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 thisadoption. The commission believes that this program will reduce ambient levels of NO

x and SO

2 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 NO

x from grandfathered EGFs, but permitted EGFs and other sources of NO

x 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 NO

x 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 theAttorney General go through staff preparation of an administrative penalty recommendation in accordance with the commission’s penalty policy. Staff obtains an agreement or litigates toobtain 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 RegisterThe 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 NO

x and SO

2 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 NO

x 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 UnitedStates 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 theCode 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 NO

x 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 NO

x 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 NO

x from grandfathered EGFs will not exceed 50% of the NO

x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO

2 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 andtrading program. Both of these programs are critical to the successful reduction of the NO

x and SO

2 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 intendedby 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 NO

x emissions, since the majority of emissions are generated by on-road and off-road mobile and area sources, and that the inclusion ofthese 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 NO

x, which has been shown to heavily influence local ozone levels" are comments without any qualifications to specific EGFs and perpetuate theopinion 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 contributeheavily 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 135near-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 NO

x emissions from EGFs are not minor, but significantly contribute to ground-level ozone formation. The preamblecomments 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 NO

x emissions from EGFs are approximately 47% of the stationary source NO

x emissions in the East Texas Region.

EPA-CAMD commented that in the proposed preamble, the cost-effectiveness numbers of $4,000 per ton of NO

x removed in the absence of emissions trading, or $2,000 per ton of NO

x removed with emissions trading, seem far too high. For example, in the May 25, 1999 Final Rule under §126 ofthe FCAA (64 FR 28300), EPA determined an average costeffectiveness of $1,468 per ton of NO

x removed from electric generating units greater than 25 megawatts with emissions trading. Estimates for cost-effectiveness of NO

x control under the Ozone Transport Committee NO

x Budget Program range from $950-1,600 per ton. Furthermore, the commenter noted that some gas-fired units can achieve an average NO

x 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 PublicUtility Commission of Texas (PUCT) and TNRCC report published in February 1999, entitled Electric Restructuring and AirQuality: 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 wereanalyzed on a unit-by-unit basis. Thus, the potential for "overcompliance" for certain generating units in cases where it maybe 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 resultingreductions 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% NO

x reductions and the 25% SO

2 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% NO

x emissions and 25% SO

2 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 Registertransfer 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 NO

x 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 recognizedthe 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 NO

x 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 137and 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 NO

x from grandfathered EGFs will not exceed 50% of the NO

x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO

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

Pre-proposal drafts of the EBTA contained several restrictionson 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 thesuccessful 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 emissionreductions 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. Theexemption 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 accountwhere 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 changeto 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 riverauthority. 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 moreclearly eliminates those units that were not intended to be cov

## 25 TexReg 138 January 7, 2000 Texas Registerered 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 ofsource. 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 1997sold 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 "NO

x allowance" consistently with the proposed definition of "SO

2 allowance," which states that an SO

2 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 "NO

x allowance" to be consistent with the definition of "SO

2 allowance."

Enron requested that §101.332(f) be revised to provide that neither a NO

x allowance nor an SO

2 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 139exceed 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 NO

x 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 NO

x 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 NO

x reductions are still reducing overall NO

x 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 "SO

2 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 bankedand 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 Registerthat EGFs not under common ownership or control may have separate compliance accounts.
Lloyd Gosselink commented under §101.332(h) that facilitieswith multiple EGFs should be allowed to have multiple compliance accounts, and that having one compliance account willpresent practical problems because different EGFs may be under different regulatory requirements. For example, permittedEGFs 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 electingEGFs 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 thereporting 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 NO

x 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 NO

x and 25% reductions in SO

2 . 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 andrequested 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 suggestedthat 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 SO

2 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 SO

2 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 SO

2 .



## ADOPTED RULES January 7, 2000 25 TexReg 141The 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 SO

2 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 NO

x /SO

2 allowance allocations if the applicant can demonstrate that the base year (1997) wasan 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 yearswould 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 commenterstated 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 NO

x and 25% for SO

2 . 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, electingEGFs 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 NO

x, SO

2 , or both. By mandating that an electing EGF obtain allowances for both NO

x and SO

2 , AE felt that participation will be severely limited. CPS commented that mandating electing facilities to obtain allowances for both NO

x and SO

2 , 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 NO

x and if applicable, SO

2 . 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 NO

x and SO

2 , 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 NO

x and if applicable, SO

2 , 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 notexceed an applicable state or federal requirement. The com

## 25 TexReg 142 January 7, 2000 Texas Registermenter 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 attainmentdemonstration 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 attainmentdemonstration which has been submitted to the EPA for approval as part of a SIP. Therefore, the commission does notbelieve that revising the rule to include these limitations is necessary. EPA-APS commented that a new §101.333(2)(D) should beadded to state that for electing EGFs located in ozone nonattainment areas, the amount of allowances shall not exceed the1990 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 NO

x and SO

2 , 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 electingEGF. This is necessary to account for state and federal regulations that became effective during the prior control period andfor 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 143TXU, 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 shutdownresults from the replacement of thermal energy from the electing EGF with thermal energy generated by any other EGF. Theequations 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. Thecommission 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 wherethe 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 theemission 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 Registerfactors 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 makesno 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 commissionbelieves 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 commissionto 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 ofallowances. Further, the commission expects to adopt SIP revisions that will require additional emission reductions from EGFsin attainment and nonattainment areas. The commission anticipates that these future SIP reductions may impact the EBTAand 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 usedfor 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 maybe 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 expeditethe review and reconciliation of compliance accounts to allot al

## ADOPTED RULES January 7, 2000 25 TexReg 145lowances 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) bemodified 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 fromreductions 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 bedefined 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 allowancesthat 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 downgrandfathered 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 Registerundefined 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 oneyear, 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 insubsequent 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 notincluding 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 ordelete §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 NO

x reductions in the area would result in an increased ambient ozone level. The TNRCC states in the proposed preamble that the NO

x 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 NO

x would result in an increase in ambient ozone levels in order to be exempt from the NO

x reduction requirements of §39.264. Neither the EPA nor the commission have made this determination. The §182(f) waiver indicates that NO

x 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 NO

x reductions will cause an increase in ozone levels; therefore, the commission believes that the NO

x 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 147commission 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 (NO

x) or sulfur dioxide (SO

2) 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) NO

x 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) SO

2 allowance–An authorization to emit SO

2 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 (NO

x) per MMBtu;
and

(ii) 1.38 pounds sulfur dioxide (SO

2) 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 underChapter 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 NO

x or, if applicable, SO

2, 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 thistitle (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 ReviewSchedule; §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, 76thLegislature, 1999, that require the commission to create a voluntary emission reduction permit (VERP) program. These newsections will be placed in a new Subchapter H, concerning Voluntary Emission Reduction Permit.
The commission also adopts new §116.601, concerning Typesof Standard Permits; §116.602, concerning Issuance of Standard Permits; §116.603, concerning Public Participation inIssuance 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 amendmentsimplement 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 asgrandfathered facilities. A grandfathered facility is one that existed at the time the legislature amended the Texas Clean AirAct (TCAA) in 1971. These facilities were not required to com

## 25 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 anynotice 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 appropriateprocedure 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 TexasUtilities 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 185Section 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 AirAct (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, SubchapterH, 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, includingemission banking and trading of allowances (EBTA), for grandfathered and electing EGFs and related permit application andpublic 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 (NO

x) and, for coal-fired grandfathered EGFs, sulfur dioxide (SO

2) 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 NO

x from grandfathered EGFs not exceed 50% of the NO

x emissions reported to the commission for 1997. Furthermore, it is the intent of the legislation that emissions of SO

2 from coal-fired grandfathered EGFs not exceed 75% of the SO

2 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 orother 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, SubchapterH, 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 NO

x for any grandfathered EGF, and PM through opacity limitations and emissions of SO

2 for coal-fired grandfathered EGFs. Owners or operators of electingEGFs 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 theadopted rule that excludes an EGF that generates electric energy primarily for internal use, but that during 1997 sold, toa 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 NO

x and, for coal-fired EGFs, PM through opacity limitations and SO

2 . 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 NO

x and, if applicable, PM through opacity limitations and SO

2 .



## 25 TexReg 186 January 7, 2000 Texas RegisterThe 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 NO

x and for coal-fired EGFs, PM through opacity limitations and SO

2 . 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 byTUC, §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 containsinformation concerning general content of the permit application for both grandfathered and electing EGFs. Emissions of air contaminants other than NO

x or, if applicable, PM through opacity limitations and SO

2 from an electing EGF already authorized by Chapter 116, are not required to be authorized underthis 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 newcontrols to comply with specified provisions in §116.617, Standard Permits for Pollution Control Projects. The commissionbelieves 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 areincreased 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 processfor 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 EGFPdoes 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 arenow 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 UnitedStates 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 forcalendar 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 187content 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 NO

x emissions from EGFs, and from coal-fired EGFs, SO

2 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 NO

x, SO

2 , and PM through opacity limitations fromgrandfathered 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 Chapter101 contains all provisions for managing allowances. For emissions of NO

x and, where applicable, SO

2 , 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 NO

x and, if applicable, SO

2 , for theprevious 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 allowancesequal to or greater than the emissions over a given control period. The adopted section implements TUC, §39.264(e) andrequires 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 NO

x and, if applicable, SO

2 . 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 SO

2 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 EGFmay 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 accuratethan 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 theOzone 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 NO

x emission budget program to reduce ambient ozone concentrations. Although Texas is not required toparticipate 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 NO

x emissions. Appendix E relies on stack testing of the facility to develop a relationship between the emissionrate and heat input. The commission believes that it is appropriate to structure the monitoring requirements of SubchapterI 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 GeneratingFacilities in El Paso County, was renamed to "Permits for Grandfathered and Electing Electric Generating Facilities in El PasoCounty." Consistent with TUC, §39.264(q), §116.916 would exempt EGFs in El Paso County from NO

x allowance requirements if the commission or EPA determines that reductions in NO

x emissions would lead to increased ambient levels of ozone. Currently, NO

x 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, NO

x reductions are not required if the attainment demonstration for compliance with the ozone National Ambient Air Quality Standard (NAAQS) can be made without a NO

x 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 Registeror otherwise, that NO

x 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 NO

x 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 onlyto reduction requirements, not permitting requirements. Regardless of this determination, grandfathered EGFs in El PasoCounty 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 permitin 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, concerningNotice 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 duringthe 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 whomay 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 Noticeof 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 NO

x emissions, and if applicable, PM through opacity limitations and SO

2 . The conditions of the electing EGF’s existing NSR permit would be altered to cross-reference the EGFP. Since the rule was revised to requirealterations to the electing EGF’s existing NSR permit, the provision in §116.920(c), concerning public notice for emissions of air contaminants other than NO

x, or if applicable, SO

2 , 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 fora 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 revisedto 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 stillapply. Therefore, the new §116.930 requires that any modifications to any facility in an EGFP are subject to the permittingrequirements 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 189FINAL 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 assessmentfor 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 ofgrandfathered 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 NO

x from grandfathered EGFs not exceed 50% of the NO

x emissions reported to the commission for 1997. Furthermore, it is the intent of the legislation that emissions of SO

2 from coal-fired EGFs not exceed 75% of the SO

2 emissions reported to the commission in 1997. NO

x and SO

2 allowances will be allocated to EGFs by January 1, 2000. To assist EGFs inmeeting the reduction requirements, a banking and trading program is adopted concurrently in Chapter 101. Although EGFsare 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 relatesto 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 andrules 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 thenew sections related to the authorization of EGFPs, the commission has determined that the rules are consistent with theapplicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal naturalresource 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 NO

x and, if applicable, SO

2 from grandfathered EGFs. This action isconsistent 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 AirMarkets Division (EPA-CAMD); EPA-Air Permits Division (EPAAPD); EPA-Air Planning Section (EPA-APS); The University ofTexas 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); ReliantEnergy (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 RegisterANALYSIS 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 reductionsshould be permanent. Three individuals stated that the commission should enforce reduced emissions from grandfathered electric generating facilities, and two more individuals addedthat 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 NO

x 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 NO

x and, if applicable SO

2 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 SO

2 , particularly to improve visibility in Big Bend. Another individual added that the commission must require a larger NO

x and SO

2 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 SO

2 as needed. As stated previously, the commission is addressing additional NO

x 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 SO

2 , 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 acap 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 forindividual 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 NO

x from grandfathered EGFs will not exceed 50% of the NO

x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO

2 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 NO

x and a 25% reduction in SO

2 within the region. SB 7 does notrequire 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 poweror 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 tomeet 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 commissionheld 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 wereposted 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 thisadoption. The commission believes that this program will reduce ambient levels of NO

x and SO

2 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 191with 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 NO

x from grandfathered EGFs, but permitted EGFs and other sources of NO

x 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 NO

x 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 theAttorney General go through staff preparation of an administrative penalty recommendation in accordance with the commission’s penalty policy. Staff obtains an agreement or litigates toobtain 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 (AccountNumber 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 NO

x and SO

2 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 NO

x 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 NO

x 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 NO

x 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 NO

x from grandfathered



## 25 TexReg 192 January 7, 2000 Texas RegisterEGFs will not exceed 50% of the NO

x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO

2 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 andtrading program. Both of these programs are critical to the successful reduction of the NO

x and SO

2 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 intendedby 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 NO

x emissions, since the majority of emissions are generated by on-road and off-road mobile andarea sources, and that the inclusion of these statements regarding the further need to reduce emissions from EGFs continuesto 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 NO

x, 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 removalof 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 NO

x 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 previousmodeling 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 NO

x 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 NO

x emissions from EGFs are approximately 47% of the stationary source NO

x emissions in the East Texas Region.

EPA-CAMD commented that the cost effectiveness numbers of $4,000 per ton of NO

x removed in the absence of emissions trading, or $2,000 per ton of NO

x removed with emissions trading, seem far too high. For example, in the May 25, 1999 Final Ruleunder §126 of the FCAA (64 FR 28300), EPA determined an average cost- effectiveness of $1,468 per ton of NO

x removed fromelectric generating units greater than 25 megawatts with emissions trading. Estimates for cost effectiveness of NO

x control under Ozone Transport Committee NO

x Budget Program range from $950- 1,600 per ton. Furthermore, the commenter noted that some gas-fired units can achieve an average NO

x 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 incorporatedinto 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’sfederal 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 193complying 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 resultedin 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. PCstated 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% NO

x reductions and the 25% SO

2 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% NO

x emissions and 25% SO

2 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 NO

x 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 NO

x 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 thepremium 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 Registerthe 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 NO

x, and for coal-fired EGFs, SO

2 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 NO

x and SO

2 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, SO

2 , 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, PM

10 , 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 NO

x and SO

2 , 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 NO

x, VOC, or particulate greater than any United States-built power plant.

The commission has made no changes in response to thesecomments. 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 thespecific reduction requirements of TUC, §39.264.They are required to achieve the 50% reduction in NO

x or the 25% reduction in SO

2 , 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, NO

x 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 NO

x 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 NO

x. Before the end of 1999, the commission will propose rules and additional amendments to the SIP that require reduction in NO

X 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 NO

X 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 NO

X reductions where they will be most effective and do not unnecessarily burden a particular segment of the economy. The specific NO

X emission limits are also established according to these goals. The reductions achieved under the adoption



## ADOPTED RULES January 7, 2000 25 TexReg 195of 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 NO

x and SO

2 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 NO

x and SO

2 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% NO

x reductions and the 25% SO

2 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 NO

x, and if applicable PM and SO

2 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 NO

x, and if applicable PM and SO

2 . 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 Registerthe 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 NO

x and/or SO

2 allowance(s) without adding or implementing any emissions control whatsoever. Instead, §39.264 provides that an EGF may meet its NO

x and/or SO

2 allowance(s) through emissions trading, in lieu of adding or implementing emissions controls. Moreover, nothing in §39.264 specifies, oreven indicates, that if the owner/operator chooses to add or implement emissions control to cause the EGF to meet its NO

x and/or SO

2 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 NO

x and/or SO

2 allowances in exchange for severe penalties if they do not comply with their allowable allocation. AE believes thatthe 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 choosesto 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 constructedto permit grandfathered EGFs and to achieve a target reduction of NO

x and, if applicable, SO

2 . The commission has madesignificant revisions to the sections in Chapter 116, Subchapter I that have simplified the application content sections andin general, the requirements of the permit program. For example, the requirements to demonstrate compliance with federal standards have been deleted. Further, the provisions regardingcontrol 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 thedefinition 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 Chapter39, 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 197legislative session. Its very specific intent is to require grandfathered EGFs to obtain a permit from the commission and to obtain reductions of NO

x and SO

2 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 ownedor operated by a person in this state, including a municipal corporation, electric cooperative, or river authority. No definitionof "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, andcontrolled 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 theterms 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 requirementsof TUC, §39.264 control over the general applicability requirements of TUC, §39.002. By interpreting TUC, §39.264 in thismanner, 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 municipalutilities and electric cooperatives to be exempt from the deregulation provisions. Municipal corporations and electric cooperatives with EGFs with nameplate capacities of 25 megawatts orless are not required to participate in the EBTA or the permitting program. Those over that amount must obtain permits andparticipate 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 thoseEGFs. The commission believes that the applicability exceptions in TUC, §39.002 are intended to exempt EGFs from thecompetition 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 whichmay 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 NO

x and SO

2 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 NO

x and, if applicable, SO

2 . 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 existingNSR 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 permitswith 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 Registerthe 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 sentenceto §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 contaminantsfrom 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 SO

2 .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 NO

x , SO

2 , 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 NO

x and, if coal- fired, SO

2 . CSW, Reliant, TXU, Lloyd Gosselink, CEED, Entergy Services, and AECT commented on §116.910(e) and §116.913(a) thatthe TNRCC does not have statutory authority to impose tenyear old BACT on contaminants other than NO

x and SO

2 . 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 NO

x and SO

2 . 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 NO

x and SO

2 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 NO

x, SO

2 , 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 NO

x, or, if applicable, SO

2 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 NO

x, SO

2 , 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 NO

x, SO

2 , 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 NO

x, SO

2 , and, by including a standard for opacity, PM.



## ADOPTED RULES January 7, 2000 25 TexReg 199Other 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 NO

x, SO

2 , 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 askedif 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 theseprograms 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 applyto 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 bedeleted, 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 sufficientinformation 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 bySeptember 1, 2000 should include contain sufficient detail regarding alternative monitoring requests. The commission needssufficient 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 Registerto 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 controlprojects, 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 agrandfathered 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 thatif 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 forpollution 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 thatany 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 anapplication 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" NO

x and SO

2 emissions. The commenter stated that the TNRCC needs to revisethis language, since electing EGFs are already authorized under their NSR permit.

The commission agrees that electing EGFs already had authorization to emit NO

x and SO

2 ; however, submitting an applicationunder Chapter 116, Subchapter I is requesting a new authorization for NO

x, and if applicable SO

2 . This authorization is necessary to allow the electing facility to obtain allowances and to participate in the EBTA. The commission believes that thisis 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 NO

X, and if applicable, SO

2 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 toopt out will become effective at the beginning of the control period following notification of the TNRCC. The commenter alsostated 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 201The 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 SO

2 . 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. Thedefinition 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 thatthe 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 NO

x from all grandfathered or electing EGFs and, where applicable, SO

2 . Section 116.913(a)(1)(C) provided that emissions from EGFs besides NO

x or SO

2 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). Thisclarifies 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 NO

x and SO

2 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 NO

x and SO

2 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 technologyunless 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 notimpose 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 Registerappropriate 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 aresubject 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 believesthat 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 requiringEGFs 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 EGFsprovides 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 NO

x 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 40CFR 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-casemonitoring 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 203Section 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 informationwas 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 permitsand 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 commissionbelieves 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 individualobjected 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 causesincreased copying costs for citizens, discourages public participation, and wastes natural resources. The individual objectedto 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 Registerby 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 forelecting 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 anEGFP. 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 ofan 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 permittingprocedures. 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 thecommission 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 205for 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 issuepermits; §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 permitsfor new construction and modifications; §382.0519, which authorizes the commission to issue voluntary emission reductionpermits, §382.05191, which authorizes public notice for voluntary emission reduction permits; §382.05193, which authorizespermits through emissions reductions, §382.055, which authorizes the commission to establish procedures for review or renewal of a permit; §382.056, which authorizes the commissionto 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, whichprovides the commission the authority to develop a comprehensive plan for the state’s air; §382.017, which authorizes thecommission 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 withthe 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 thecommission 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 Registerthe 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 (NO

x) emissions and, if applicable, sulfur dioxide (SO

2) and particulate matter (PM) emissions. The application mustinclude 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 themeasurement 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 NO

x, and if applicable, SO

2 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 (NO

x) emissions from all grandfathered and electing electric generating facilities (EGF);

(B) sulfur dioxides (SO

2) 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 withChapter 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 NO

x and, where applicable, SO

2, 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 mustmeet 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 (NO

x) emissions in pounds per hour shall be determined using a
NO

x 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 NO

x CEMS, NO

x emissions in pounds per hour shall be determined by multiplying pounds of
NO

x 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 NO

x and a diluent (carbon dioxide (CO

2) or oxygen (O

2)) 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 NO

x emissions in lbs/hr.

(C) The procedures in 40 CFR Part 75, Appendix E, concerning Optional NO

x Emissions Estimation Protocol for Gas-fired Peaking Units and Oil-fired Peaking Units, may be used to estimate
the NO

x 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 beforeapproving a request for alternative monitoring. Alternative monitoring shall be incorporated into the EGFP.

(4) emissions in pounds per hour shall be determined using the NO

xCEMS 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) NO

x 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 RegisterMMBtu/hr. The procedures in 40 CFR Part 60, Appendix A, Method
19 shall be used to convert the measured concentration of NO

x and a diluent (CO

2 or O

2) 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
NO

x 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 PasoCounty 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 appropriateprocedure 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 CoastalNatural 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 ofthe Coastal Coordination Council (Council). The proposed action is consistent with the coastal public lands regulations whichthe 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 CodeChapter 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