TITLE 30.ENVIRONMENTAL QUALITY

Part 1. TEXAS COMMISSION ON ENVIRONMENTAL QUALITY

Chapter 37. FINANCIAL ASSURANCE

Subchapter W. FINANCIAL ASSURANCE FOR QUARRIES

30 TAC §§37.9160, 37.9165, 37.9170, 37.9175, 37.9180, 37.9185, 37.9190, 37.9195, 37.9200, 37.9205, 37.9210, 37.9215, 37.9220, 37.9225, 37.9230, 37.9235, 37.9240

The Texas Commission on Environmental Quality (TCEQ or commission) adopts new §§37.9160, 37.9165, 37.9170, 37.9175, 37.9180, 37.9185, 37.9190, 37.9195, 37.9200, 37.9205, 37.9210, 37.9215, 37.9220, 37.9225, 37.9230, 37.9235, and 37.9240. Section 37.9215 is adopted with changes to the proposed text as published in the March 24, 2006, issue of the Texas Register (31 TexReg 2395). Sections 37.9160, 37.9165, 37.9170, 37.9175, 37.9180, 37.9185, 37.9190, 37.9195, 37.9200, 37.9205, 37.9210, 37.9220, 37.9225, 37.9230, 37.9235, and 37.9240 are adopted without changes and the text will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

Senate Bill (SB) 1354, 79th Legislature, 2005, amended Texas Water Code (TWC), Chapter 26, by adding new Subchapter M, Water Quality Protection Areas; specifically §§26.551 - 26.562. The statute addresses permitting, financial responsibility, inspections, water quality sampling, enforcement, cost recovery, and interagency cooperation with regard to quarry operations. The requirements of the statute are applicable to a pilot program in the John Graves Scenic Riverway, a stretch of the Brazos River watershed downstream of the Morris Shepard Dam on the Possum Kingdom Reservoir, and extending to the county line between Parker and Hood Counties.

Chapter 37, new Subchapter W, implements §26.553(f)(2) and §26.554. Subchapter W establishes financial assurance requirements for the John Graves Scenic Riverway pilot program. The purpose of the financial assurance requirements is to assure that adequate funds will be readily available to cover the costs of reclamation and restoration associated with quarries. Financial assurance is important for two reasons. First, it assures environmental needs related to quarries and the John Graves Scenic Riverway will be addressed using funds arranged by the responsible party. Second, it prevents delays in addressing environmental needs by assuring funds that are readily available.

A corresponding rulemaking is published in this issue of the Texas Register that includes the addition of new Subchapter H, Regulation of Quarries in the John Graves Scenic Riverway to 30 TAC Chapter 311, Watershed Protection.

SECTION BY SECTION DISCUSSION

New Subchapter W is adopted to be added to Chapter 37 to provide financial assurance requirements relating to reclamation and restoration related to quarries in the John Graves Scenic Riverway. The new subchapter also outlines the administrative procedures and requirements relating to these types of financial assurance. It is intended to be used in coordination with provisions of Chapter 311 and with certain provisions of Chapter 37, Subchapters A and B.

Adopted new §37.9160, Applicability, identifies who is subject to this subchapter and those entities that are exempt.

Adopted new §37.9165, Definitions, defines terms that are used throughout this subchapter.

Adopted new §37.9170, Financial Assurance Requirements for Reclamation and Restoration, indicates that owners and operators required to demonstrate financial assurance for reclamation or restoration must comply with certain general financial assurance requirements in Chapter 37, Subchapters A and B. Subsection (a)(1) - (4) outlines portions of Chapter 37, Subchapter B, that will not apply to owners and operators of quarries. Subsection (a)(4) specifies that §37.161 applies to quarry owners and operators, except that mechanism and wording requirements of a standby trust fund are found in this subchapter rather than Chapter 37, Subchapter B. Subsection (b) indicates that the amount of financial assurance must at least equal the current cost estimate. Required financial assurance amounts are further described in Chapter 311, Subchapter H. These amounts are reflective of the cost estimates referred to in this subchapter. Subsection (c) requires certain wordings for mechanisms and provides that the executive director will determine the acceptability of any mechanism submitted. The timing for providing the mechanism is described in subsection (d). For ease of administration and cost to the owner or operator, subsection (e) allows the use of a single financial assurance mechanism for both reclamation and restoration as long as the total mechanism amount is not less than the total required for each purpose. Continuous financial assurance until release by the executive director is provided for in subsection (f). Subsection (g) describes the conditions under which financial assurance mechanisms would be called upon. Finally, subsection (h) sets out the requirements for the standby trust agreement that must be established in conjunction with surety bonds and irrevocable letters of credit.

Adopted new §37.9175, Financial Assurance Mechanisms for Reclamation, allows the use of a trust agreement, a surety bond guaranteeing payment, an irrevocable standby letter of credit, insurance, a financial test, or a corporate guarantee as mechanisms for meeting financial assurance requirements for reclamation.

Adopted new §37.9180, Financial Assurance Mechanisms for Restoration, allows the use of a trust agreement, a surety bond guaranteeing payment, an irrevocable standby letter of credit, insurance, a financial test, or a corporate guarantee as mechanisms for meeting financial assurance requirements for restoration.

Adopted new §37.9185, Trust Fund Requirements, describes the requirements for a trust fund used to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9190, Trust Agreement Wording, describes the wording required for a trust agreement evidencing establishment of a trust fund.

Adopted new §37.9195, Surety Bond Guaranteeing Payment Requirements, describes the requirements for a payment surety bond used to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9200, Payment Bond Wording, describes the wording required for a payment surety bond used to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9205, Irrevocable Standby Letter of Credit Requirements, describes the requirements for a letter of credit used to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9210, Irrevocable Standby Letter of Credit Wording, describes the wording required for a letter of credit used to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9215, Insurance Requirements, describes the requirements for insurance used to demonstrate financial assurance for reclamation or restoration. Subsection (b) is adopted with changes to the proposed text to require an insurer be either licensed in Texas or eligible as an excess and surplus lines carrier in Texas rather than in one or more states.

Adopted new §37.9220, Certificate of Insurance Wording, describes the wording required for a certificate of insurance used to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9225, Financial Test Requirements, describes the financial and reporting requirements for entities choosing to self-insure by using a financial test as a means of demonstrating financial assurance for reclamation or restoration.

Adopted new §37.9230, Financial Test Wording, describes the wording of the document that must be submitted by the chief financial officer of an entity choosing to use the financial test to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9235, Corporate Guarantee Requirements, describes the requirements for a higher tiered parent corporation choosing to use a corporate guarantee on behalf of a quarry owner or operator to demonstrate financial assurance for reclamation or restoration.

Adopted new §37.9240, Corporate Guarantee Wording, describes the wording required of a corporate guarantee used to demonstrate financial assurance for reclamation or restoration.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rules do not meet the definition of a "major environmental rule." Under Texas Government Code, §2001.0225, "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 rules are intended to implement SB 1354, relating to the regulation of ongoing mining and quarrying within the newly created John Graves Scenic Riverway. The adopted rules in Chapter 37 clarify financial assurance requirements for quarries located in the John Graves Scenic Riverway. The adopted rules do not adversely affect, in a material way, the economy, a section 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 rules simply clarify financial assurance requirements for quarries located in the John Graves Scenic Riverway. The adopted rules do not meet the definition of a major environmental rule as defined in the Texas Government Code.

Furthermore, the adopted rulemaking action does not meet any of the four applicable requirements listed in Texas Government Code, §2001.0225(a). Texas Government Code, §2001.0225(a), only applies to a major environmental rule adopted by an agency, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

In this case, the adopted rules do not meet any of these applicability requirements. First, the adopted rules are specifically required to implement SB 1354. Second, the adopted rules do not exceed a requirement of state law, because they are being adopted to implement SB 1354. Third, the rules do not exceed an express requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program. Fourth, the commission does not adopt these rules solely under the general powers of the agency, but rather under the authority of SB 1354, which directs the commission to implement rules under TWC, Chapter 26. These rules do not meet the criteria for a major environmental rule as defined by Texas Government Code, §2001.0225.

The commission solicited public comment on the draft regulatory impact analysis in the March 24, 2006, issue of the Texas Register (31 TexReg 2395). No comments were received on the draft regulatory impact analysis.

TAKINGS IMPACT ASSESSMENT

The commission evaluated this rulemaking action and performed an analysis of whether this action would constitute a takings under Texas Government Code, Chapter 2007. The adopted new rules in Chapter 37 clarify financial assurance requirements for quarries located in the John Graves Scenic Riverway. The promulgation and enforcement of the rules will not affect private real property in a manner that would require compensation to private real property owners under the United States Constitution or the Texas Constitution. The adopted rules also will not affect private real 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 rulemaking does not meet the definition of a takings under Texas Government Code, §2007.002(5). Therefore, the adopted rules will not constitute a takings under Texas Government Code, Chapter 2007.

The commission solicited public comment on the takings impact assessment in the March 24, 2006, issue of the Texas Register (31 TexReg 2397). No comments were received on the takings impact assessment.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission reviewed the adopted rulemaking and found that the rules are neither identified in Coastal Coordination Act Implementation Rules, 31 TAC §505.11(b)(2), relating to Actions and Rules Subject to the Coastal Management Program, nor will it affect any action/authorization identified in Coastal Coordination Act Implementation Rules, 31 TAC §505.11(a)(6). Therefore, the adopted rules are not subject to the Texas Coastal Management Program.

PUBLIC COMMENT

A public hearing on the proposed rules was held in Mineral Wells on April 6, 2006, at 6:30 p.m. at the Mineral Wells City Hall Annex, Council Chambers, 115 Southwest First Street. Written comments were received from the Brazos River Conservation Coalition (BRCC) and Jackson Sjoberg, McCarthy & Wilson, L.L.P. (McCarthy) on behalf of multiple parties including one individual, the Rocking "W" Ranch, and the BRCC. The comments generally concerned technical issues.

RESPONSE TO COMMENTS

BRCC commented that the insurance company providing coverage for financial assurance per §37.9215(b) should be licensed in Texas rather than in one or more states as the proposal indicated.

The commission agrees that requiring the insurer to be either licensed in Texas or eligible to provide insurance as an excess or surplus lines insurer in Texas would improve the rule by making the insurer subject to Texas regulations rather than the rules of another state, which may have unfamiliar requirements. To affect this change, the commission, at adoption, deleted the phrase "in one or more states" and replaced it with "in Texas" in subsection (b) of §37.9215.

BRCC also expressed concern about the financial test proposed in §37.9225 and the corporate guarantee proposed in §37.9235 since these "self-insuring" mechanisms represent the greatest risk that private funds would not be available to fund any necessary cleanup and/or restoration. Specifically, it urged the commission to require available assets of the owner/operator at least exceed the current cost estimates, review whether a $10 million tangible net worth was sufficient, and look at the historical success/failure of these mechanisms in other agency programs. McCarthy further stated that the commission should abandon financial test and corporate guarantee options in favor of letters of credit and insurance.

The commission disagrees that the financial test needs to be amended or abandoned. The structure of the financial test adopted under these rules is based upon the financial test developed and adopted by the United States Environmental Protection Agency in 1982 for the industrial hazardous waste program. Along with other financial ratios, the test requires the owner/operator to have audited financial statements reflecting a tangible net worth exceeding both $10 million and at least six times the amount of environmental liabilities assured through use of the financial test. The test is designed to be a predictor of the likelihood of bankruptcy and allow the owner/operator to obtain another financial assurance mechanism prior to bankruptcy. While it has been used most extensively in the industrial hazardous waste program, it is an available mechanism in an additional seven programs at TCEQ. To date, no failures of the test have been noted at TCEQ. Accordingly, the commission has made no changes to the proposed rules in response to these comments.

STATUTORY AUTHORITY

The new sections are adopted under TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; §5.102, which establishes the commission's general authority necessary to carry out its jurisdiction; §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; §5.120, which states that the commission shall administer the law so as to promote the judicious use and maximum conservation and protection of the quality of the environment and the natural resources of the state; §26.011, which provides the commission with authority to adopt any rules necessary to carry out its powers, duties, and policies and to protect water quality in the state; and §26.027, which authorizes the commission to issue permits and amendments to permits for the discharge of waste or pollutants into or adjacent to water in the state. Rulemaking authority is expressly granted to the commission to adopt rules under TWC, Chapter 26, as amended by SB 1354, §2.

The adopted new rules implement SB 1354, which creates TWC, Chapter 26, new Subchapter M. SB 1354, §2, expressly requires the commission to adopt rules adequate to protect the water resources in a water quality protection area for inclusion in any authorization, including an individual or general permit.

§37.9215.Insurance Requirements.

(a) An owner or operator may satisfy the requirements of financial assurance by obtaining insurance that conforms to the requirements of this subchapter and submitting an originally signed certificate to the executive director.

(b) At a minimum, the insurer must be licensed to transact the business of insurance, or eligible to provide insurance as an excess or surplus lines insurer, in Texas.

(c) The wording of the certificate of insurance must be identical to the wording specified in §37.9220 of this title (relating to Certificate of Insurance Wording).

(d) The insurance policy must be issued for a face amount at least equal to the current cost estimate for reclamation or restoration, except when a combination of mechanisms are used in accordance with §37.41 and §37.9170 of this title (relating to Use of Multiple Financial Assurance Mechanisms and Financial Assurance Requirements for Reclamation and Restoration). Actual payments by the insurer shall not change the face amount, although the insurer's future liability shall be lowered by the amount of the payments.

(e) The insurance policy must guarantee that funds shall be available to provide for reclamation at the quarry or restoration related to the quarry. The policy shall also guarantee that once reclamation at the quarry or restoration related to the quarry begins, the issuer shall be responsible for paying out funds, up to an amount equal to the face amount of the policy, upon the direction of the executive director, to such party or parties as the executive director specifies.

(f) An owner or operator or any other person authorized to perform reclamation or restoration may request reimbursement for expenditures for reclamation at the quarry or restoration related to the quarry by submitting itemized bills to the executive director. The request shall include an explanation of the expenses and all applicable itemized bills. The owner or operator may request reimbursement for partial reclamation at the quarry or restoration related to the quarry only if the remaining value of the policy is sufficient to cover the maximum remaining costs of reclamation at the quarry or restoration related to the quarry. Within 60 days after receiving bills for reclamation at the quarry or restoration related to the quarry, the executive director shall determine whether the reclamation or restoration expenditures are in accordance with the approved reclamation or restoration activities or are otherwise justified, and if so, shall instruct the insurer to make reimbursement in such amounts as the executive director specifies in writing. If the executive director has reason to believe that the maximum cost of reclamation or restoration will be greater than the face amount of the policy, the executive director may withhold reimbursement of such amounts as deemed prudent until the executive director determines, in accordance with this subchapter, that the owner or operator is no longer required to maintain financial assurance requirements for reclamation at the quarry or restoration related to the quarry of the facility. If the executive director does not instruct the insurer to make such reimbursements, the executive director shall provide the owner or operator with a detailed written statement of reasons.

(g) The owner or operator shall maintain the policy in full force and effect until the executive director consents to termination of the policy. Failure to pay the premium, without substitution of alternate financial assurance as specified in this subchapter, shall constitute a violation of these regulations, warranting such remedy as the executive director deems necessary. Such violation shall be deemed to begin upon receipt by the executive director of a notice of future cancellation, termination, or failure to renew due to nonpayment of the premium, rather than upon the date of expiration of the policy.

(h) The policy must provide that the insurer may not cancel, terminate, or fail to renew the policy except for failure to pay the premium. The automatic renewal of the policy shall, at a minimum, provide the insured with the option of renewal at the face amount of the expiring policy. If there is a failure to pay the premium, the insurer may elect to cancel, terminate, or fail to renew the policy by sending notice by certified mail to the owner or operator and the executive director. Cancellation, termination, or failure to renew may not occur, however, during 120 days beginning with the date of receipt of the notice by both the executive director and the owner or operator, as evidenced by the return receipts.

(i) Cancellation, termination, or failure to renew may not occur and the policy shall remain in full force and effect in the event that on or before the date of expiration:

(1) the executive director deems the quarry abandoned;

(2) the permit expires, is terminated, is revoked, or a new or renewal permit is denied;

(3) reclamation or restoration is ordered by the executive director of the commission or by a United States district court or other court of competent jurisdiction;

(4) the owner or operator is named as debtor in a voluntary or involuntary proceeding under Title 11 (Bankruptcy), United States Code; or

(5) the premium due is paid.

(j) Each policy must contain a provision allowing assignment of the policy to a successor owner or operator. Such assignment may be conditional upon consent of the insurer, provided such consent is not unreasonably refused.

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 July 14, 2006.

TRD-200603760

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 24, 2006

For further information, please call: (512) 239-5017

Chapter 101. GENERAL AIR QUALITY RULES

Subchapter H. EMISSIONS BANKING AND TRADING

7. CLEAN AIR INTERSTATE RULE

30 TAC §§101.501 - 101.504, 101.506, 101.508

The Texas Commission on Environmental Quality (commission) adopts new §§101.501 - 101.504, 101.506, and 101.508. Sections 101.501 - 101.503 are adopted without changes to the proposed text as published in the March 17, 2006, issue of the Texas Register (31 TexReg 1872) and will not be republished. Sections 101.504, 101.506, and 101.508 are adopted with changes to the proposed text and will be republished.

The new sections will be submitted to the United States Environmental Protection Agency (EPA) as revisions to the state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

On May 12, 2005, EPA promulgated the Clean Air Interstate Rule (CAIR) to assist nonattainment areas in downwind states in achieving compliance with the national ambient air quality standards (NAAQS) for particulate matter less than or equal to 2.5 microns (PM 2.5 ) and eight-hour ozone. Twenty-eight eastern states and the District of Columbia were identified as upwind contributors to the nonattainment of the PM2.5 and eight-hour ozone NAAQS prompting the requirement for the reduction in emissions of sulfur dioxide (SO 2 ) and/or oxides of nitrogen (NO x ). Twenty-three states, including Texas, and the District of Columbia were found to contribute to the downwind nonattainment of the PM 2.5 NAAQS and are required to make reductions in annual emissions of SO 2 and NO x . Twenty-five states and the District of Columbia, not including Texas, were found to contribute to the downwind nonattainment of the eight-hour ozone NAAQS and are required to reduce ozone-season NO x emissions. EPA modeled 37 states, including Texas, for PM 2.5 contribution using the Community Multiscale Air Quality Model. A criterion of 0.2 micrograms per cubic meter (æg/m 3 ) was used for determining whether SO 2 and NO x emitted in one state made a significant contribution to PM 2.5 nonattainment in another state. State-by-state, zero-out modeling was then used to quantify the state's contribution for SO 2 and NO x . EPA's modeling demonstrated that Texas provided a contribution of 0.29 æg/m 3 with two downwind "linkages," Madison County, Illinois and St. Clair County, Illinois. For ozone contribution, 31 states in the eastern United States were modeled. Since Texas was not included in the ozone modeling exercise, EPA did not determine that Texas contributed to ozone nonattainment in another state.

The NO x and SO 2 reduction requirements under CAIR are being implemented in two phases by providing states with declining budgets. For NO x , Phase I begins in 2009 and continues through the year 2014 with Texas receiving an initial NO x budget of 181,014 tons annually. The Phase II NO x budget will begin in 2015, with Texas receiving 150,845 tons annually. State SO 2 budgets are based on the allowance allocations provided under Federal Clean Air Act (FCAA), Title IV. Annual state budgets for Phase I, 2010 - 2014, are based on a 50% reduction of Title IV allowances allocated in the affected state. The initial SO 2 budget for Texas during Phase I is 320,946 tons. For Phase II, 2015 and thereafter, SO 2 budgets are based on a 65% reduction of Title IV allowances allocated in the affected state, with Texas receiving 224,662 tons.

EPA provided states with two compliance options for meeting the reduction requirements under CAIR: 1) meet the state's emission budget by requiring electric generating units (EGUs) to participate in an EPA-administered interstate cap and trade program; or 2) meet an individual state emissions budget through measures of the state's choosing. The 79th Legislature, 2005, enacted House Bill (HB) 2481, §2 (codified at Texas Health and Safety Code (THSC), Texas Clean Air Act (TCAA), §382.0173), requiring Texas to participate in the EPA-administered interstate cap and trade program through the incorporation by reference of the CAIR model trading rule. HB 2481 also provided specific direction for the methodology to be used in allocating the NO x trading budget provided to Texas, identified an amount of CAIR NOx allowances to be set aside for new sources, and specified that reductions associated with CAIR would only be required from new and existing EGUs and not from other sources of SO 2 and NOx emissions.

HB 2481 amended THSC, Chapter 382 by adding §382.0173. THSC, §382.0173(a) requires that the commission adopt rules "incorporat{ing} by reference 40 CFR Subparts AA through II and Subparts AAA through III of Part 96 and 40 CFR Subpart HHHH of Part 60." Additionally, THSC, §382.0173(b) requires the commission to "make permanent allocations that are reflective of the allocation requirements of 40 CFR Subparts AA through HH and Subparts AAA through HHH of Part 96 and 40 CFR Subpart HHHH of Part 60 . . . at no cost . . . using the {EPA's} allocation method as specified by Section 60.4142(a)(1)(I), as issued by that agency on May 12, 2005, or 40 CFR Section 96.142(a)(1)(I), as issued by that agency on May 18, 2005, as applicable with the exception of nitrogen oxides which shall be allocated according to the additional requirements of Subsection (c)." THSC, §382.0173(c) provides additional requirements regarding NO x allocations, specifically a requirement to maintain a special reserve of allocations for certain units, and requirements relating to establishing allocations for specific control periods. THSC, §382.0173(d) provided that its provisions applied only while the federal rules were enforceable and that the provisions of HB 2481 do "not limit the authority of the commission to implement more stringent emissions control requirements."

The commission interprets these requirements together in order to provide effect to the expressed intent of the legislature. Specifically, the commission interprets the language of new THSC, §382.0173(d) as not restricting existing authority to require further emissions control requirements, but not to interfere with, or change, the requirements of the CAIR NO x and SO 2 , or the Clean Air Mercury Rule (CAMR) mercury emission trading programs. The legislature expressed clear intent that the commission implement the CAIR and CAMR emission trading programs by requiring the incorporation by reference of the CAIR and CAMR program rules as promulgated by EPA, and requiring the use of EPA-specified allocation methodology, with some exceptions for CAIR NO x allowances.

Under 40 Code of Federal Regulations (CFR) Part 96, EPA promulgated a model rule for the CAIR NO x Annual Trading Program. This model rule is a market-based cap and trade system designed to reduce the costs of complying with the new NO x and SO2 reduction requirements. The CAIR model rule designates respective budgets for annual NO x and SO2 emissions within each state to be applied to all fossil fuel-fired boilers and turbines serving an electrical generator with a nameplate capacity greater than 25 megawatts of electricity (MWe) and producing electricity for sale. The model rule provides flexibility in complying with the NO x and SO 2 reduction requirements through the unrestricted banking of excess allowances and the trading of allowances between EGUs in affected CAIR states under common caps. For example, EGUs in Texas will be allowed to trade NO x allowances with other CAIR states participating in the CAIR NOx Annual Trading Program, while the trading of SO2 allowances will be permissible with CAIR states participating in the CAIR SO 2 Trading Program or the Title IV SO 2 Allowance Trading Program. The model rule provides states flexibility in the allocation methodology used to determine CAIR NO x allowance allocations for each CAIR NO x unit. CAIR states are then responsible for submitting the CAIR NO x allowance allocations to EPA for recordation. CAIR SO 2 allowance allocations are distributed by EPA based on the CAIR source's Title IV SO 2 allowance allocation. Under the CAIR model rule, EPA takes responsibility for establishing CAIR compliance accounts for each CAIR source and maintaining an allowance tracking system to record the deposit, transfer, and deduction for compliance of all CAIR allowances. CAIR sources are required, under the model rule, to demonstrate compliance through the installation and operation of continuous emissions monitoring systems as required under 40 CFR Part 75. Finally, the model rule requires all elements of the CAIR NO x Annual Trading Program and CAIR SO 2 Trading Program to be federally enforceable through the issuance of a CAIR permit as a complete and separable portion of the CAIR source's Title V permit.

As directed by HB 2481, the commission is adopting rules under Chapter 101, Subchapter H, Division 7 to incorporate 40 CFR Part 96, Subpart AA - Subpart II and Subpart AAA - Subpart III by reference for the purpose of complying with the CAIR. In addition, the commission is adopting specific rules under Subchapter H, Division 7 regarding the methodologies and procedures for determining each CAIR NO x source's CAIR NO x allowance allocation in lieu of the CAIR NO x allowance allocation methodologies and procedures under 40 CFR Part 96, Subpart EE. The adopted rules apply to EGUs that are defined as a stationary, fossil fuel-fired boiler or a stationary, fossil fuel-fired combustion turbine serving at any time, since the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe and producing electricity for sale. The adopted rules also apply to cogeneration units serving at any time a generator with nameplate capacity of more than 25 MWe and supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 megawatts hours (MWh), whichever is greater, to any utility power distribution system for sale.

The adopted rules distribute the NO x trading budget provided to Texas to each CAIR NO x unit based on the specific direction provided under HB 2481. A total amount of CAIR NO x allowances equal to 9.5% of the Texas NO x trading budget will be set-aside as a special reserve for distribution to new units commencing operation on or after January 1, 2001. The remaining 90.5% of the Texas NO x trading budget will be distributed to units having commenced operation before January 1, 2001, based on a three-year average of the unit's historical heat input adjusted for the type of fuel burned. In performing the fuel adjustment, a unit's historical heat input will be multiplied by the following: 90% for coal-fired, 50% for natural gas-fired, and 30% for all other fossil fuels. The adopted rules will also incorporate an allocation update beginning with the 2016 control period, and for the control period beginning every five years thereafter. The allocation update will adjust the baseline heat input used in determining the CAIR NO x allowance allocation for each CAIR NO x unit. In addition to the Texas NO x trading budget, the CAIR model trading rule provides an additional pool of allowances available for allocation in the 2009 control period to those CAIR NO x units achieving early NO x reductions in 2007 and 2008, or whose compliance with the CAIR NO x reduction requirements for the 2009 control period will create undue risk to the reliability of electricity supply during the year 2009. This pool of NO x allowances, the compliance supplement pool, equates to an additional 772 tons for Texas. The adopted rules specify the requirements for a compliance supplement pool allowance request by CAIR NO x sources.

The commission is concurrently adopting an additional rulemaking to 30 TAC Chapter 122, Federal Operating Permits Program, in this issue of the Texas Register to implement HB 2481. The commission is also adopting a CAIR SIP, rules to implement CAMR, and a CAMR state plan.

SECTION BY SECTION DISCUSSION

SUBCHAPTER H, EMISSIONS BANKING AND TRADING

Division 7, Clean Air Interstate Rule

Section 101.501, Applicability

Adopted new §101.501 states that the requirements of Subchapter H, Division 7 apply to any stationary, fossil fuel-fired boiler or stationary, fossil fuel-fired combustion turbine meeting the applicability requirements under 40 CFR Part 96, Subpart AA or Subpart AAA. 40 CFR Part 96, Subpart AA and Subpart AAA define applicable units as stationary, fossil fuel-fired boilers or combustion turbines serving at any time, since the startup of the unit's combustion chamber, a generator with a nameplate capacity of more than 25 MWe producing electricity for sale. The referenced applicability also includes cogeneration units serving at any time a generator with a nameplate capacity of more than 25 MWe and supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.

Section 101.502, Clean Air Interstate Rule Trading Program

Adopted new §101.502 incorporates by reference, with the exception of the requirements specified under Subchapter H, Division 7, the CAIR trading programs for annual NO x and SO 2 codified under 40 CFR Part 96, Subpart AA - Subpart II and Subpart AAA - Subpart III finalized on May 12, 2005. The section requires owners and operators of sources subject to 40 CFR Part 96, Subpart AA - Subpart II or Subpart AAA - Subpart III to comply with the requirements of those subparts. The new section also specifies that the methodologies and procedures for determining CAIR NO x allowance allocations in 40 CFR Part 96, Subpart EE are replaced by the requirements of this division.

The requirements of 40 CFR Part 96, Subpart AA - Subpart II relate to the CAIR NO x Annual Trading Program. Specifically, 40 CFR Part 96, Subpart AA describes the general provisions of the CAIR NOx Annual Trading Program, including definitions; applicability; an exemption from the permitting, monitoring, and reporting requirements of the program for retired units; and standard procedural requirements of the program. 40 CFR Part 96, Subpart BB outlines the procedures for the authorization of and the responsibilities of the CAIR designated representative and alternate CAIR designated representative for a CAIR NO x source. The CAIR designated representatives or alternates represent and, through their representations, actions, inactions, or submissions, legally bind each owner and operator of a CAIR NO x source in all matters pertaining to the CAIR NO x Annual Trading Program. 40 CFR Part 96, Subpart CC describes the requirement for each CAIR NOx source to apply for and obtain a CAIR permit containing all applicable CAIR NO x Annual Trading Program requirements for each CAIR NO x unit at the source. The CAIR permit is required to be a complete and separable portion of the CAIR NO x source's Title V operating permit. 40 CFR Part 96, Subpart EE outlines the methods and procedures for determining CAIR NO x allowance allocations, including the annual CAIR NO x trading budgets for each state. The methods and procedures identified in 40 CFR Part 96, Subpart EE are replaced by the requirements of this division. 40 CFR Part 96, Subpart FF describes the CAIR NO x allowance tracking system, the methods for establishing compliance and general accounts, the recording of CAIR NOx allowance allocations into a CAIR NO x source's compliance account, the procedures for deducting allowances for compliance, and the banking of CAIR NO x allowances. Deductions for compliance are based on the monitoring and reporting requirements under 40 CFR Part 96, Subpart HH, with "penalty" deductions for exceeding the amount of allowances held in a compliance account being equal to three times the number of tons in excess. 40 CFR Part 96, Subpart GG describes the procedures for the submission and recordation of CAIR NO x allowance trades. 40 CFR Part 96, Subpart HH provides the requirements for emissions monitoring, initial certification and recertification procedures for monitors, recordkeeping, and reporting.

40 CFR Part 96, Subpart II describes the opt-in provisions for the CAIR NO x Annual Trading Program. The opt-in provisions apply to any unit that is not already a CAIR NO x unit under 40 CFR §96.104 or covered by a retired unit exemption; has or is qualified to have a Title V operating permit; vents all emissions to a stack; and can meet the monitoring, recordkeeping, and reporting requirements of 40 CFR Part 96, Subpart HH. CAIR NO x opt-in units are required to apply for and obtain a CAIR permit as prescribed under 40 CFR Part 96, Subpart CC. Units electing to opt-in to the CAIR NO x Annual Trading Program must monitor and report the NO x emission rate and heat input of the unit in accordance with the monitoring and reporting requirements of 40 CFR Part 96, Subpart HH for the entire control period prior to the date that the unit elects to enter the CAIR NO x Annual Trading Program. The baseline heat input and baseline emission rate for each CAIR NO x opt-in unit is dependent upon the number of control periods for which the unit has monitored and reported heat input and emission rate data in accordance with 40 CFR Part 96, Subpart HH. If the unit has monitored and reported for only one control period, the baseline heat input and emission rate shall be the unit's total heat input and NO x emission rate for the control period immediately preceding the date that the unit elects to opt-in. For units that have monitored and reported for more than one control period, the baseline heat input and emission rate shall be the average of the most recent three-year period. The opt-in provisions of 40 CFR Part 96, Subpart II allow opt-in units to choose from two different allocation methods for receiving an allocation of CAIR NO x allowances. The general approach allocates CAIR NO x allowances to opt-in units at 70% of their baseline NO x emission rate with no additional reductions required after the 2009 control period. An alternative approach allocates CAIR NO x allowances at the baseline levels for the 2009 - 2014 control periods, but requires deeper reductions starting in 2015. The CAIR NO x allowance allocation for each control period beginning in 2015, and thereafter, is based on a NOx emission rate equal to the lesser of 0.15 lb of NOx /million British thermal units (MMBtu), the unit's baseline emission rate, or the most stringent state or federal NO x emission limit applicable for any time during the applicable control period. Owners or operators of units may elect to opt-in to the CAIR NOx Annual Trading Program without electing to opt-in to the CAIR SO 2 Trading Program and may withdraw from participation in the CAIR NO x Annual Trading Program after five years of participation.

The requirements of 40 CFR Part 96, Subpart AAA - Subpart III relate to the CAIR SO 2 Trading Program and closely mirror the requirements for the CAIR NO x Annual Trading Program under 40 CFR Part 96, Subpart AA - Subpart II. An element unique to the CAIR SO 2 Trading Program is the program's interaction and coordination with the Title IV SO 2 Trading Program. Under the CAIR SO 2 Trading Program, states have no discretion in the approach to the allocation of SO 2 allowances because EPA is basing the CAIR SO 2 allowance allocations on the SO 2 allocations already provided under the Title IV SO 2 Trading Program. Compliance with the CAIR SO 2 Trading Program is coordinated with the Title IV SO 2 Trading Program through requiring the use of Title IV SO 2 allowances for compliance with the CAIR SO 2 Trading Program at increasing ratios. Title IV SO 2 allowances allocated for 2010 - 2014 are retired for compliance with the CAIR SO2 Trading Program at a ratio of two allowances per ton of emissions. SO 2 allowances allocated for 2015, and thereafter, are retired for compliance at a ratio of 2.86 allowances per ton of emissions. Title IV SO 2 allowances allocated for years prior to 2010 may be used for compliance with the CAIR SO 2 Trading Program at a ratio of one allowance per ton of emissions. SO 2 allowances are freely transferrable between sources covered by the Title IV SO 2 Trading Program and sources covered by the CAIR SO 2 Trading Program.

40 CFR Part 96, Subpart AAA describes the general provisions of the CAIR SO 2 Trading Program including definitions; applicability; an exemption for retired units; and standard procedural requirements of the program. 40 CFR Part 96, Subpart BBB outlines the procedures for the authorization of and the responsibilities of the CAIR designated representative and alternate CAIR designated representative for a CAIR SO 2 source. 40 CFR Part 96, Subpart CCC describes the requirement for each CAIR SO2 source to apply for and obtain a CAIR permit containing all applicable CAIR SO 2 Trading Program requirements for each CAIR SO 2 unit at the source. 40 CFR Part 96, Subparts DDD and EEE are reserved. 40 CFR Part 96, Subpart FFF describes the CAIR SO 2 allowance tracking system, establishment of compliance accounts and general accounts, recordation of CAIR SO 2 allowance allocations, procedures for deducting allowances for compliance, and the banking of CAIR SO 2 allowances. Deductions for compliance are based on the monitoring and reporting requirements under 40 CFR Part 96, Subpart HHH, with "penalty" deductions for exceeding the amount of allowances held in a compliance account being equal to three times the number of tons in excess.

The deduction of SO 2 allowances outlined under 40 CFR Part 96, Subpart FFF for compliance with the CAIR SO 2 Trading Program is determined in two steps. First, CAIR SO 2 allowances are deducted at a 1:1 ratio for compliance with the Title IV SO 2 Trading Program. Secondly, any additional deductions for compliance with the CAIR SO 2 Trading Program are made at the applicable ratio for the vintage year allowance being deducted. For example, a CAIR SO 2 unit emits 100 tons of SO 2 in the 2012 control period. The compliance account for the CAIR SO 2 unit holds 70 vintage 2009 allowances and 60 vintage 2012 allowances. For compliance with the Title IV SO 2 Trading Program, 70 vintage 2009 allowances and 30 vintage 2012 allowances are deducted to cover the 100 tons of emissions, leaving an excess of 30 vintage 2012 allowances. However, for CAIR, the tonnage equivalent for the deduction to comply with the Title IV SO 2 Trading Program is 85 allowances (70 vintage 2009 allowances and 30 vintage 2012 allowances used at a 2:1 ratio). The remaining 30 vintage 2012 allowances not needed for compliance with the Title IV SO2 Trading Program are deducted from the compliance account at a 2:1 ratio to make up the 15-ton difference for compliance with the CAIR.

40 CFR Part 96, Subpart GGG describes the procedures for submitting and recording CAIR SO 2 allowance trades. 40 CFR Part 96, Subpart HHH provides the requirements for emissions monitoring, certification and recertification of monitors, recordkeeping, and reporting. 40 CFR Part 96, Subpart III describes the opt-in provisions for the CAIR SO 2 Trading Program. The opt-in provisions apply to an owner or operator of a unit that is not already a CAIR SO 2 unit under 40 CFR §96.204 or that is/that is not covered by a retired unit exemption; has or is qualified to have a Title V operating permit; vents all emissions to a stack; and can meet the monitoring, recordkeeping, and reporting requirements of 40 CFR Part 96, Subpart HHH. Owners or operators of CAIR SO2 opt-in units are required to apply for and obtain a CAIR permit as prescribed under 40 CFR Part 96, Subpart CCC. Owners or operators of units electing to opt-in to the CAIR SO 2 Trading Program are required to monitor and report the SO 2 emission rate and heat input of the unit in accordance with the monitoring and reporting requirements of 40 CFR Part 96, Subpart HHH for the entire control period prior to the date that the unit elects to enter the CAIR SO 2 Trading Program. The baseline heat input and baseline emission rate for each CAIR SO 2 opt-in unit is dependent upon the number of control periods for which the unit has monitored and reported heat input and emission rate data in accordance with 40 CFR Part 96, Subpart HHH. If the owners or operators of a unit have monitored and reported for only one control period, the baseline heat input and emission rate shall be the unit's total heat input and SO 2 emission rate for the control period immediately preceding the date that the unit elects to opt-in. For owners or operators of units that have monitored and reported for more than one control period, the baseline heat input and emission rate shall be the average of the most recent three-year period. The opt-in provisions of 40 CFR Part 96, Subpart III allow owners or operators of opt-in units to choose from two different allocation methods for receiving an allocation of CAIR SO 2 allowances. The general approach allocates CAIR SO 2 allowances to opt-in units at 70% of their baseline SO 2 emission rate with no additional reductions required after the 2010 control period. An alternative approach allocates CAIR SO 2 allowances at the baseline levels for the 2010 - 2014 control periods, but requires deeper reductions starting in 2015. The CAIR SO 2 allowance allocation for each control period beginning in 2015, and thereafter, is based on an SO 2 emission rate equal to the lesser of the unit's baseline emission rate multiplied by 10% or the most stringent state or federal SO 2 emission limit applicable for any time during the applicable control period. Owners or operators of units may elect to opt-in to the CAIR SO 2 Trading Program without electing to opt-in to the CAIR NO x Annual Trading Program and may withdraw from participation in the CAIR SO 2 Trading Program after five years of participation.

Section 101.503, Clean Air Interstate Rule Oxides of Nitrogen Annual Trading Budget

Adopted new §101.503 specifies that the NO x trading budget for annual allocations of CAIR NO x allowances for each control period in 2009 - 2014 and for 2015, and thereafter, are equivalent to the tons of NO x emissions listed for Texas in the state trading budget under 40 CFR §96.140. As finalized on May 12, 2005, 40 CFR §96.140 provides Texas with an annual NO x trading budget of 181,014 tons for each control period in 2009 - 2014, and 150,845 tons for each control period in 2015, and thereafter. The adopted rule also reserves an amount of CAIR NO x allowances equivalent to 9.5% of the Texas NO x trading budget for allocation to new units. This new unit set-aside equates to 17,196 tons of CAIR NO x allowances for each control period in 2009 - 2014, and 14,330 tons of CAIR NO x allowances for each control period in 2015, and thereafter.

Section 101.504, Timing Requirements for Clean Air Interstate Rule Oxides of Nitrogen Allowance Allocations

New §101.504 outlines the deadlines by which the executive director shall submit to EPA the CAIR NO x allowance allocations for each CAIR NO x unit subject to this division. The adopted rule requires the executive director to submit to EPA by October 31, 2006, the CAIR NO x allowance allocations for the 2009 - 2014 control periods, as determined under §101.506(c) for CAIR NO x units with a historical baseline heat input. Based on comment, the required deadlines for submittal to EPA of the CAIR NO x allowance allocations under §101.504(a)(2) - (4) were revised from June 1 to October 31 on the basis that historically the Acid Rain data to be used in determining the proper allocations for future control periods is not available until well after the June 1 time period. The commission notes that preliminary Acid Rain data from the previous control period is typically available by June of the following year, however, this data may be revised by a source prior to the data being finalized. In order to avoid any potential complications with revised data impacting the allocation of CAIR NO x allowances, the commission is electing to delay submittal of CAIR NO x allowance allocations until such allocations can be based on final Acid Rain data. In addition, an October 31 deadline date is consistent with the submittal deadline date for the 2009 - 2014 control periods under §101.504(a)(1) and with the submittal deadline date for CAIR NO x allocations from the new unit set-aside under §101.504(b). As a result, the adopted rule requires submittal to EPA of the CAIR NO x allowance allocations determined under §101.506(c) for the 2015 control period by October 31, 2011, and for the 2016 control period by October 31, 2014. Beginning with the 2017 control period, and for each control period thereafter, the CAIR NO x allowance allocations determined under §101.506(c) shall be submitted to EPA 14 months prior to each applicable control period. For example, the CAIR NO x allowance allocations determined under §101.506(c) for the 2017 control period shall be submitted to EPA by October 31, 2015, 14 months prior to January 1, 2017. The adopted deadline for submittal of the CAIR NO x allowance allocations for the 2016 control period, and for each control period thereafter, allows for a minimum lead time of no more than 14 months between recordation of the allocation by EPA and the start of the applicable control period. This lead time is in conflict with the required minimum lead time of three years provided under 40 CFR §51.123(o)(2)(ii) for states declining the adoption of the allocation provisions under 40 CFR Part 96, Subpart EE. However, the submittal deadline is consistent with HB 2481, requiring the update of the baseline heat input used in determining the CAIR NOx allowance allocations for CAIR NO x units in Texas. HB 2481 states that beginning with the 2016 control period, and for each control period beginning every five years thereafter, the baseline heat input for all affected CAIR NO x units must be updated to reflect the average of the three highest amounts of the unit's adjusted control period heat input during control periods one through five of the previous seven control periods. For example, the baseline period for determining CAIR NO x allowance allocations for the 2016 control period would be the average of the unit's three highest amounts of adjusted heat input from the 2009 - 2013 control periods. To meet the required three-year minimum lead time under 40 CFR §51.123(o)(2)(ii), the allocations for the 2016 control period must be submitted no later than January 1, 2013. Therefore, the federal requirement does not allow for the completion of the baseline period mandated under HB 2481. The deadline for submission of CAIR NO x allowance allocations 14 months in advance of each control period beginning in 2016, and thereafter, allows for the completion of the mandated baseline period, as well as provides time for the executive director to determine the updated CAIR NO x allowance allocations and submit the updated allocations to EPA.

New §101.504 also specifies the deadline for submission of CAIR NOx allowance allocations by the executive director to EPA for allowances distributed from the new unit set-aside. For the 2009 control period, and for each control period thereafter, the CAIR NO x allowance allocations determined under §101.506(d) and (e) shall be submitted to EPA by October 31 of that control period. The new rule also describes the manner in which EPA will allocate CAIR NO x allowances should the executive director fail to submit the allocations by the deadlines in §101.504(a). Should the CAIR NO x allowance allocations not be provided to EPA by the applicable deadlines in §101.504(a) for each control period, in accordance with 40 CFR §96.141, EPA will assume that the CAIR NO x allowance allocations for the applicable control period are the same as for the immediately preceding control period. If the applicable control period is 2015, EPA will assume the CAIR NO x allowance allocations equal 83% of the allocations for the 2014 control period. For units receiving allocations under §101.506(d) and (e), if the executive director fails to submit the CAIR NO x allowance allocations by the applicable deadline in §101.504(b), EPA will assume that no CAIR NO x allowances are to be allocated, for the applicable control period, to any CAIR NO x unit that is otherwise receiving an allocation from the new unit set-aside.

Section 101.506, Clean Air Interstate Rule Oxides of Nitrogen Allowance Allocations

Adopted new §101.506 describes the methodology to be used in distributing CAIR NO x allowances, in tons, for each CAIR NOx unit subject to this division. For units commencing operation before January 1, 2001, CAIR NO x allowances are allocated based on a three-year average historical heat input, in MMBtu, adjusted for the type of fuel burned. For each control period in 2009 - 2015, the baseline heat input for units commencing operation before January 1, 2001, will be the average of the three highest amounts of the unit's historical heat input, adjusted for fuel type, from calendar years 2000 - 2004. Beginning with the 2016 control period, and for the control period beginning every five years thereafter, the baseline heat input for units commencing operation prior to January 1, 2001, will be adjusted to reflect the average of the three highest amounts of the unit's control period heat input, adjusted for fuel type, from control periods one through five of the previous seven control periods. The fuel type adjustments are performed by multiplying a unit's baseline heat input by the following: 90% for coal-fired, 50% for natural gas-fired, and 30% for all other fossil fuels.

For units commencing operation on or after January 1, 2001, CAIR NOx allowances are allocated for each control period in 2009 - 2014 from the new unit set-aside identified under §101.503(b). Beginning with the 2015 control period, units commencing operation on or after January 1, 2001, and operating each calendar year for a period of five or more consecutive years will be eligible to receive their CAIR NO x allowance allocation from the general NO x trading budget on a modified output basis. The baseline heat input will be the average of the three highest amounts of the unit's total converted control period heat input from the first five years of operation. In response to comment, the rule was revised to delete the phrase "and for each control period thereafter" from subsection (b)(2) to eliminate the possibility of two conflicting baseline periods applying to units commencing operation on or after January 1, 2001, and operating for five or more consecutive years, for the 2016 control period, and for every fifth control period thereafter. Beginning with the 2016 control period, and for the control period beginning every five-year period after 2016, the baseline heat input will be adjusted to reflect the average of the three highest amounts of the unit's total converted control period heat input from control periods one through five of the previous seven control periods. To calculate a unit's converted control period heat input on a modified output basis, the unit's gross electrical output is multiplied by a heat rate conversion factor of 7,900 British thermal units per kilowatt-hour (Btu/kWh) for coal-fired units and 6,675 Btu/kWh for natural gas- and oil-fired units. For cogeneration units, the converted heat input is calculated by converting the available thermal output, in Btu, of useable steam to an equivalent heat input by dividing the thermal output by a general boiler/heat exchanger efficiency of 80%. For combustion turbine cogeneration units, the converted heat input is calculated by first converting the available thermal output of useable steam from the heat recovery steam generator or heat exchanger to an equivalent heat input by dividing the thermal output by a general boiler/heat exchanger efficiency of 80%. Then the electrical generation from the combustion turbine must be added after conversion to an equivalent heat input by multiplying the electrical output by 3,413 Btu/kWh. The sum yields the total equivalent heat input for the combustion turbine cogeneration unit.

The adopted allocation methodology distributes 90.5% of the Texas NOx trading budget to each CAIR NO x unit with a baseline heat input determined under §101.506(a) or (b)(2) or (3) in proportion to each CAIR NO x unit's share of baseline heat input to the total baseline heat input for all CAIR NO x units with a baseline heat input determined under §101.506(a) or (b)(2) or (3). For units that commence operation on or after January 1, 2001, and that have not established a historical baseline heat input in accordance with §101.506(b)(2) or (3), CAIR NO x allowances are allocated from the new unit set-aside beginning with the later of the 2009 control period or the first control period after the control period in which the new unit commences commercial operation. The adopted allocation methodology requires the executive director to distribute CAIR NO x allowances from the new unit set-aside upon receipt of a request from the CAIR designated representative for the CAIR NO x unit. Submittal of each request for a CAIR NO x allowance allocation from the new unit set-aside is required on or before July 1 of the first control period for which the request is being made and after the date that the CAIR NO x unit commences commercial operation. CAIR NO x allowances requested from the new unit set-aside will not be allocated in excess of the new unit's total tons of NO x emissions reported to EPA for the previous control period. On or after July 1 of each control period, the executive director shall review each CAIR NO x allowance allocation request, determine the sum of all CAIR NOx allowance allocation requests, and allocate CAIR NO x allowances from the new unit set-aside for the control period. If the amount of CAIR NO x allowances in the new unit set-aside is greater than or equal to the sum of all CAIR NO x allowances requested, then the executive director shall allocate the amount of CAIR NO x allowances requested. If the amount of CAIR NO x allowances in the new unit set-aside is less than the sum of all CAIR NO x allowances requested, then the executive director shall allocate to each new CAIR NO x unit an amount of CAIR NOx allowances in proportion to the amount of CAIR NOx allowances requested by a CAIR NO x unit to the total amount of CAIR NO x allowances requested by all CAIR NO x units. In the adopted allocation methodology, new units begin receiving allowances from the set-aside for the control period immediately following the control period in which the new unit commences commercial operation based on the unit's emissions reported for the previous control period. Therefore, a CAIR NO x source operating a new unit is required to hold allowances covering the emissions from the new unit for the control period in which the new unit commences commercial operation, but will not receive an allocation for that control period. CAIR NO x allowance allocations for a new unit in subsequent control periods will continue to be based on the unit's emissions from the previous control period until the unit establishes a baseline in accordance with §101.506(b)(2) or (3).

In response to comments, the commission has added new subsection (g) specifying a deadline for units completing their first five years of commercial operation to certify with the executive director the data needed to establish a baseline heat input under §101.506(b)(2) or (3). The new subsection requires the gross electrical output of the generator or generators served by the unit and total heat energy of any steam produced by the unit to be submitted in writing to the executive director by the latter of July 1, 2011, or July 1 of the control period immediately following the unit's fifth consecutive year of commercial operation. This deadline provides an adequate amount of time for the CAIR designated representative to submit the relevant data and for the executive director to determine the CAIR NO x allocations from the general NO x trading budget and the new unit set-aside prior to the applicable EPA allocation submittal deadlines.

Due to the timing requirements under §101.504 for submittal of CAIR NO x allowance allocations to EPA, a new unit completing its first five years of commercial operation and establishing its baseline under §101.506(b)(2) or (3) by the end of the 2010 control period will begin receiving a CAIR NO x allowance allocation from the general NO x trading budget beginning with the 2015 control period. Based on the requirements of HB 2481, beginning with the 2016 control period, and for the control period beginning every five years thereafter, a new unit must complete its first five consecutive years of operation prior to the end of the revised five-year baseline period in order to receive an allocation from the general NO x trading budget. For example, to receive an allocation from the general NO x trading budget for the 2016 control period, a new unit must complete its first five consecutive years of operation by the end of the 2014 control period. The new unit will then begin receiving CAIR NO x allowances from the general NOx trading budget beginning with the 2016 control period based on the average of the three highest amounts of the unit's converted control period heat input during the 2009 - 2014 control periods. All CAIR NO x allowance allocations under the adopted allocation methodology are rounded to the nearest whole allowance.

New §101.506 allows for the distribution of any unallocated CAIR NOx allowances remaining in the new unit set-aside for a given control period to CAIR NO x units with a historical baseline heat input receiving an allocation under §101.506(c). These existing units will each receive an additional allocation proportional to the ratio of their original allocation to the state's existing unit allocation, 90.5% of the Texas NO x trading budget. This distribution is performed by multiplying the amount of unallocated CAIR NO x allowances remaining in the set-aside by each CAIR NO x unit's allocation determined under §101.506(c), divided by 90.5% of the Texas NO x trading budget, and rounded to the nearest whole allowance.

The adopted new §101.506 also requires, for the purposes of determining CAIR NO x allowance allocations, a CAIR NOx unit's control period heat input, status as coal-fired or natural gas-fired, and total tons of NO x emissions during a calendar year to be determined in accordance with 40 CFR Part 75, to the extent the unit was otherwise subject to those requirements for the year. If a CAIR NO x unit was not otherwise subject to the requirements of 40 CFR Part 75 for the year, the unit's control period heat input, status as coal-fired or natural gas-fired, and total tons of NOx emissions during a calendar year will be based on the best available data reported to the executive director.

Section 101.508, Compliance Supplement Pool

New §101.508 outlines the requirements for the allocation of additional CAIR NO x allowances for the 2009 control period from the compliance supplement pool for Texas provided under 40 CFR §96.143. As promulgated on May 12, 2005, 40 CFR §96.143 provides Texas with an additional 772 CAIR NO x allowances under the compliance supplement pool. The adopted rule allows the compliance supplement pool allowances to be distributed to those CAIR NO x units that achieve early NO x reductions in 2007 and 2008, beyond any applicable state or federal emission limitation during those years. CAIR NO x units seeking an additional allocation from the compliance supplement pool for early NOx reductions in 2007 and 2008 are required to monitor and report the unit's NO x emission rate and heat input in accordance with the continuous emissions monitoring and reporting requirements under 40 CFR Part 96, Subpart HH for the entire control period in which the early reductions are being generated. The CAIR designated representative is required to submit to the executive director by July 1, 2009, a request for an allocation of CAIR NO x allowances from the compliance supplement pool in an amount not to exceed the sum of the CAIR NO x unit's emission reductions, in tons, during 2007 and 2008, that were not necessary to comply with any state or federal emission limitation applicable during those years.

In addition, new §101.508 provides for the allocation of additional CAIR NO x allowances from the compliance supplement pool for CAIR NO x units whose compliance with the CAIR NO x annual trading program in the 2009 control period will create undue risk to the reliability of electricity supply during 2009. The CAIR designated representative is required to submit to the executive director by July 1, 2009, a request for an allocation of CAIR NOx allowances from the compliance supplement pool in an amount not to exceed the minimum amount of CAIR NO x allowances necessary to remove the risk to the reliability of electricity supply. In such requests, the CAIR designated representative is required to demonstrate that in the absence of the additional allocation to the unit, the unit's compliance with the CAIR NO x annual trading program during the 2009 control period will create an undue risk to electric reliability during 2009. This demonstration is required to show that it would not be feasible to obtain a sufficient amount of electricity from other electric generation facilities or obtain a sufficient amount of CAIR NO x allowances from the compliance supplement pool by making early NO x reductions in 2007 and 2008.

The executive director shall review each request for an additional allocation from the compliance supplement pool and, if approved, allocate CAIR NOx allowances for the 2009 control period to CAIR NOx units covered by a request. If the amount of CAIR NO x allowances in the compliance supplement pool is greater than or equal to the sum of all CAIR NO x allowances requested, then the executive director shall allocate the amount of CAIR NO x allowances requested. If the amount of CAIR NO x allowances in the compliance supplement pool is less than the sum of all CAIR NO x allowances requested, then the executive director shall allocate to each CAIR NO x unit covered under a request an amount of CAIR NO x allowances in proportion to the amount of CAIR NO x allowances requested by a CAIR NO x unit to the total amount of CAIR NO x allowances requested by all CAIR NOx units. The adopted rule requires the executive director to determine and submit to EPA by November 30, 2009, the CAIR NO x allowance allocations from the compliance supplement pool.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking in light of the regulatory impact analysis requirements of Texas Government Code, §2001.0225, and determined that the adopted rulemaking meets the definition of a "major environmental rule" as defined in that statute. A "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 rulemaking does not, however, meet any of the four applicability criteria for requiring a regulatory impact analysis for a major environmental rule, which are listed in Texas Government Code, §2001.0225(a). Texas Government Code, §2001.0225, applies only to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

The adopted new rules are an incorporation by reference of the federal CAIR. The CAIR includes EPA-administered emissions trading programs that will be governed by model rules provided in the CAIR, which states may incorporate by reference. The EPA found that Texas is among several states that contribute significantly to nonattainment of the NAAQS for PM 2.5 in downwind states. The EPA is requiring these upwind states to revise their SIPs to include control measures to reduce emissions of SO 2 and/or NO x , which are precursors to PM 2.5 formation. Reducing upwind precursor emissions will assist downwind PM 2.5 nonattainment areas to achieve the NAAQS in a more equitable, cost-effective manner than if those areas implemented local emissions reductions alone. The EPA has specified the amount of each state's required reductions, but each state has flexibility to choose the measures by which it achieves them. If states choose to control EGUs, then they must establish a budget or cap for those sources. The CAIR defines the EGU budgets for the affected states if the states choose to control only EGUs or if they choose to control other sources to achieve some or all of their reductions. States may adopt the CAIR NO x model allowance allocation methodology or choose an alternative method to allocate the state budget of NO x emissions allowances to sources in the state.

Specifically, the adopted rulemaking would incorporate by reference the CAIR model emissions trading rules located in 40 CFR Part 96, Subpart AA - Subpart II, and Subpart AAA - Subpart III. In addition, the rulemaking adopts an alternative NO x allowance allocation methodology for Texas CAIR NO x sources in lieu of the model rule methodology in 40 CFR Part 96, Subpart EE. The adopted rulemaking fulfills the requirements of HB 2481, enacted by the 79th Legislature, to incorporate CAIR by reference; to adopt an alternate NO x allowance allocation methodology; to specify the sources to which the trading program is applicable; to set the timing requirements to report annual unit allocations to EPA; to detail the operation of the compliance supplement pool; to specify that a percentage of the state's annual allocation will be set-aside for new units; and to provide that allowances will be available at no cost.

The incorporation of CAIR requires emission reductions from certain new and existing stationary, fossil fuel-fired electric utility units, including boilers and combustion turbines, and certain cogeneration units that meet specific applicability criteria. The adopted incorporation of the federal rule is intended to protect the environment and to reduce risks to human health and safety from environmental exposure by reducing NO x and SO 2 emissions from upwind states so that downwind states may reach attainment of the NAAQS for PM 2.5 . The CAIR includes revisions to the Acid Rain Program regulations under FCAA, Title IV, particularly the regulatory provisions governing the SO 2 cap and trade program. The revisions streamline the operation of the Acid Rain SO 2 cap and trade program and facilitate its interaction with the CAIR trading program. While the required emissions reductions of these programs are based on controls that are known to be highly cost-effective for EGUs, the requirements may have adverse impacts on certain utilities, which could be considered a sector of the economy. The exact cost to each unit cannot be predicted, but significant costs to comply with the emission reductions programs may be expected for at least some units that install or upgrade emission controls or that purchase allowances. While the adopted rulemaking is intended to protect human health and the environment, it may adversely affect in a material way sources in the state that fall under the applicability requirements in the federal rule. Cost and benefits of the CAIR were analyzed by EPA during the federal notice and comment rulemaking for the CAIR. CAIR is a required federal program, and the ability of states to modify its requirements is limited.

The adopted rulemaking implements the requirements of the FCAA. Under 42 United States Code (USC), §7410(a)(2)(D), each SIP must contain adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment of the NAAQS in any other state. While 42 USC, §7410 generally does not require specific programs, methods, or reductions in order to meet the standard, SIPs must include "enforceable emission limitations and other control measures, means or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter" (42 USC, Chapter 85, Air Pollution Prevention and Control). The provisions of the FCAA recognize that states are in the best position to determine what programs and controls are necessary or appropriate in order to meet the NAAQS. This flexibility allows states, affected industry, and the public, to collaborate on the best methods for attaining the NAAQS for the specific regions in the state. Even though the FCAA allows states to develop their own programs, this flexibility does not relieve a state from developing a program that meets the requirements of 42 USC, §7410. States are not free to ignore the requirements of 42 USC, §7410, and must develop programs to assure that their contributions to nonattainment areas are reduced so that these areas can be brought into attainment on schedule. Additionally, states have further obligations under 42 USC, §7410(a)(2)(D), to address interstate transport of pollutants that contribute significantly to nonattainment in, or interfere with maintenance by, another state. In the CAIR, EPA found that 28 states and the District of Columbia contribute significantly to nonattainment of the PM 2.5 or eight-hour ozone NAAQS in downwind areas. The EPA is requiring these upwind states to revise their SIPs to include control measures to reduce emissions of SO 2 and/or NO x , with limited flexibility. Adoption of the federal CAIR and participation in its emissions cap and trade approach for annual SO 2 and NO x emissions to reduce downwind PM 2.5 is the method the state has chosen to achieve those reductions in a flexible and cost-effective manner.

The requirement to provide a fiscal analysis of proposed regulations in the Texas Government Code was amended by Senate Bill (SB) 633 during the 75th Legislature, 1997. The intent of SB 633 was to require agencies to conduct a regulatory impact analysis of extraordinary rules. These are identified in the statutory language as major environmental rules that will have a material adverse impact and will exceed a requirement of state law, federal law, or a delegated federal program, or are adopted solely under the general powers of the agency. With the understanding that this requirement would seldom apply, the commission provided a cost estimate for SB 633 that concluded "based on an assessment of rules adopted by the agency in the past, it is not anticipated that the bill will have significant fiscal implications for the agency due to its limited application." The commission also noted that the number of rules that would require assessment under the provisions of the bill was not large. This conclusion was based, in part, on the criteria set forth in the bill that exempted proposed rules from the full analysis unless the rule was a major environmental rule that exceeds a federal law.

As discussed earlier in this preamble, the FCAA does not always require specific programs, methods, or reductions in order to meet the NAAQS; thus, states must develop programs for each area contributing to nonattainment to help ensure that those areas will meet the attainment deadlines. Because of the ongoing need to address nonattainment issues, and to meet the requirements of 42 USC, §7410, the commission routinely proposes and adopts SIP rules. The legislature is presumed to understand this federal scheme. If each rule proposed for inclusion in the SIP was considered to be a major environmental rule that exceeds federal law, then every SIP rule would require the full regulatory impact analysis contemplated by SB 633. This conclusion is inconsistent with the conclusions reached by the commission in its cost estimate and by the Legislative Budget Board (LBB) in its fiscal notes. Since the legislature is presumed to understand the fiscal impacts of the bills it passes, and that presumption is based on information provided by state agencies and the LBB, the commission believes that the intent of SB 633 was only to require the full regulatory impact analysis for rules that are extraordinary in nature. While the SIP rules will have a broad impact, that impact is no greater than is necessary or appropriate to meet the requirements of the FCAA. For these reasons, rules adopted for inclusion in the SIP fall under the exception in Texas Government Code, §2001.0225(a), because they are required by federal law.

The commission has consistently applied this construction to its rules since this statute was enacted in 1997. Since that time, the legislature has revised the Texas Government Code, but left this provision substantially unamended. It is presumed that "when an agency interpretation is in effect at the time the legislature amends the laws without making substantial change in the statute, the legislature is deemed to have accepted the agency's interpretation." (Central Power & Light Co. v. Sharp , 919 S.W.2d 485, 489 (Tex. App. Austin 1995), writ denied with per curiam opinion respecting another issue , 960 S.W.2d 617 (Tex. 1997); Bullock v. Marathon Oil Co. , 798 S.W.2d 353, 357 (Tex. App. Austin 1990, no writ ). Cf. Humble Oil & Refining Co. v. Calvert , 414 S.W.2d 172 (Tex. 1967); Dudney v. State Farm Mut. Auto Ins. Co. , 9 S.W.3d 884, 893 (Tex. App. Austin 2000); Southwestern Life Ins. Co. v. Montemayor , 24 S.W.3d 581 (Tex. App. Austin 2000, pet. denied ); and Coastal Indust. Water Auth. v. Trinity Portland Cement Div. , 563 S.W.2d 916 (Tex. 1978)).

The commission's interpretation of the regulatory impact analysis requirements is also supported by a change made to the Texas Administrative Procedure Act (APA) by the legislature in 1999. In an attempt to limit the number of rule challenges based upon APA requirements, the legislature clarified that state agencies are required to meet these sections of the APA against the standard of "substantial compliance." The legislature specifically identified Texas Government Code, §2001.0225, as falling under this standard. The commission has substantially complied with the requirements of Texas Government Code, §2001.0225.

The specific intent of the adopted rulemaking is to protect the environment and to reduce risks to human health by adoption of the federal CAIR by reference, and to specify some components of the trading program for which the federal rule allows for flexibility of choice by the state. The adopted rulemaking does not exceed a standard set by federal law or exceed an express requirement of state law. No contract or delegation agreement covers the topic that is the subject of this adopted rulemaking. Finally, this adopted rulemaking was not developed solely under the general powers of the agency, but is required by THSC, TCAA, §382.0173. Therefore, this adopted rulemaking is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because although the adopted rulemaking meets the definition of a "major environmental rule," it does not meet any of the four applicability criteria for a major environmental rule.

TAKINGS IMPACT ASSESSMENT

The commission evaluated the adopted rulemaking and performed an assessment of whether Texas Government Code, Chapter 2007, is applicable. The specific purpose of the adopted rulemaking is to incorporate by reference the federal CAIR emissions trading rules located in 40 CFR Part 96, Subpart AA - Subpart II and Subpart AAA - Subpart III, and to specify some components of the trading program for which the federal rule allows for flexibility of choice by the state. The 79th Legislature enacted HB 2481, which created a requirement in THSC, TCAA, §382.0173 to adopt the federal CAIR program rules by reference. Texas Government Code, §2007.003(b)(4), provides that Texas Government Code, Chapter 2007 does not apply to this adopted rulemaking because it is an action reasonably taken to fulfill an obligation mandated by federal law and by state law.

In addition, the commission's assessment indicates that Texas Government Code, Chapter 2007 does not apply to these adopted rules because this is an action that is taken in response to a real and substantial threat to public health and safety; that is designed to significantly advance the health and safety purpose; and that does not impose a greater burden than is necessary to achieve the health and safety purpose. Thus, this action is exempt under Texas Government Code, §2007.003(b)(13). EPA promulgated the CAIR rule to reduce NO x and SO 2 emissions from upwind states so that downwind states may reach attainment of the NAAQS for PM 2.5 . The adopted rules will enable Texas to implement the federal emissions budget and trading program and impose its requirements on new and existing fossil fuel-fired electric utility units, ultimately ensuring reductions of NO x and SO2 emissions. The action will specifically advance the health and safety purpose by reducing PM 2.5 levels through an emissions cap and gradual reductions in emissions of NO x and SO 2 . The rules specifically target a category of sources with significant NO x and SO 2 emissions, and through the cap and trade program support cost-effective control strategies. Consequently, the adopted rulemaking meets the exemption criteria in Texas Government Code, §2007.003(b)(4) and (13). For these reasons, Texas Government Code, Chapter 2007 does not apply to this adopted rulemaking.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq .), and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Texas Coastal Management Program. As required by §281.45(a)(3) and 31 TAC §505.11(b)(2), concerning Actions and Rules Subject to the Coastal Management Program, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and determined that the action is consistent with the applicable CMP goals and policies. The CMP goal applicable to this rulemaking action is the goal to protect, preserve, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas (31 TAC §501.12(l)). No new sources of air contaminants are authorized and the adopted new rules will maintain at least the same level of or increase the level of emissions control as the existing rules. The CMP policy applicable to this rulemaking action is the policy that commission rules comply with federal regulations in 40 CFR, to protect and enhance air quality in the coastal areas (31 TAC §501.32). This rulemaking action complies with 40 CFR Part 51, concerning Requirements for Preparation, Adoption, and Submittal of Implementation Plans. Therefore, in accordance with 31 TAC §505.22(e), the commission affirms that this rulemaking action is consistent with CMP goals and policies.

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

The requirements of 42 USC, §7410 are applicable requirements of 30 TAC Chapter 122. Facilities that are subject to the Federal Operating Permit Program will be required to obtain, revise, reopen, and renew their federal operating permits as appropriate in order to include CAIR.

PUBLIC COMMENT

The commission conducted public hearings on the proposed rules on April 11, 2006, in Austin; April 12, 2006, in Fort Worth; and April 13, 2006, in Houston. During the public comment period, which closed at 5:00 p.m., April 17, 2006, the commission received comments from American Electric Power (AEP); American Wind Energy Association (AWEA); Association of Electric Companies of Texas, Inc. (AECT); Austin Physicians for Social Responsibility (APSR); Blue Skies Alliance; Calpine; Clean Water Action (CWA); Entergy Services Inc. (Entergy); EPA; Environment Texas; FPL Group (FPL); Gulf Coast Lignite Coalition (GCLC); League of Women Voters of Texas (LWV); Lone Star Chapter of Sierra Club (Lone Star Sierra Club); NRG Texas (NRG); Public Citizen; Representative Dennis Bonnen (District 25); Senator Ken Armbrister (District 18); Sierra Club of Dallas-Fort Worth (DFW Sierra Club); Sierra Club - Houston Regional Group (Houston Sierra Club); Southwestern Public Services (SPS); Suez Energy Generation NA, Inc. (SEGNA); Texas Association of Business (TAB); Texas Impact; Texas Mining and Reclamation Association (TMRA); The Sustainable Energy and Economic Development Coalition (SEED); TXU Power (TXU); and 139 individuals.

NRG supported comments submitted by GCLC; TMRA supported comments submitted by AECT and GCLC; GCLC supported comments submitted by TMRA and AECT; and Entergy supported comments submitted by AECT.

TXU, Entergy, AECT, and SPS concurred with Representative Bonnen's comments.

RESPONSE TO COMMENTS

FEDERAL APPROVABILITY

EPA commented that the proposed SIP and rule language for the submittal of CAIR NO x allocations by the state to EPA under §101.504 do not meet the federal deadline requirements under 40 CFR §51.123(o)(2)(ii). EPA commented that with the current proposed rule language, EPA could only conditionally approve the Texas CAIR rule and SIP, and the SIP and rule language would need to align with the federal deadline requirement to receive final federal approval.

The commission appreciates the comment, and is aware that the CAIR NOx allocation time line adopted in this rule does not meet the federal time line requirements in the revised final CAIR rule that was published in the Federal Register on April 28, 2006. The commission has been directed by the legislature under HB 2481 to adopt the proposed time line. Commission staff are in the process of notifying legislators that the directive in HB 2481 will not accommodate the requirements of the revised final federal CAIR program.

EPA commented that participation in the federal CAIR trading programs for NO x and SO 2 requires the adoption of rules substantively identical to the 2006 revised CAIR model trading rules. If the commission cannot adopt the CAIR model rule revisions promulgated in 2006, EPA will consider a conditional approval of these rules. The necessary revisions include: incorporating by reference the revisions to 40 CFR Part 96 Subparts AA - II and Subparts AAA - III; updating references to the applicability of CAIR and the definition of an electric generating unit or cogeneration unit; incorporating the revisions to the CAIR designated representative; revising the proposed allocation methodology under §101.504(c) to address amendments to 40 CFR §96.141; and revising the figures in §101.506(b)(2)(C) and (b)(3)(C) to use "3,413 Btu/kWh" to be consistent with revisions to 40 CFR §96.142. EPA also commented that the commission would need to incorporate the changes to the Acid Rain program at 40 CFR Parts 72 - 74 and 78 as published in the Federal Register on April 28, 2006 to interact seamlessly with CAIR.

The commission appreciates the comment, and is aware that subsequent rule changes regarding the revised final CAIR that were published in the Federal Register on April 28, 2006, will need to be incorporated into the Texas rules and CAIR SIP in order to receive final federal approval. The commission anticipates initiating rulemaking and a SIP revision proposing to incorporate these needed changes in the near future.

RENEWABLE ENERGY SET-ASIDE

AWEA, Public Citizen, SEED, Blue Skies Alliance, and Lone Star Sierra Club commented that the adopted rules should include a set-aside for renewable energy. AWEA recommended a method to incorporate renewable energy into the proposed CAIR NO x allocation methodology under §101.506, and provided information from the State and Territorial Air Pollution Program Administrators and the Association of Local Air Pollution Control Officials regarding model alternative allocation methodology for renewable energy. The suggested method would provide a direct allocation of NO x allowances for renewable energy technologies as new sources using the modified output-based approach. Renewable energy sources in operation for less than five years would receive an allocation from the new unit set-aside by multiplying their generation output by a standard allocation rate of 1.5 pounds of NO x per megawatt hour. Renewable energy sources in operation for five or more years would receive an allocation from the general pool by converting their generation output to heat input using the proposed heat rate for non-coal units of 6,675 Btu/kWh. In addition, the AWEA commented that the proposed new unit set-aside of 9.5% should be altered to adequately accommodate future growth estimates, including growth for renewable resources. In addition, one individual commented that the commission should promote renewable energy and energy conservation.

The rules have not been revised in response to these comments. HB 2481, 79th Legislature, 2005, directed the commission to incorporate by reference the federal CAIR model trading rule and make permanent allocations that are reflective of the NO x allocation requirements of 40 CFR Part 96, Subpart AA - Subpart HH. Under 40 CFR §96.104, the CAIR trading program only applies to fossil fuel-fired electric generating units with a nameplate capacity greater than 25 MWe and producing electricity for sale. The methodology outlined under 40 CFR Part 96, Subpart EE and the specific direction given under HB 2481 limit the methodology for determining NO x allocations to fossil fuel-fired electric generating units only. Since renewable energy is not classified as fossil fuel-fired electric generation, the commission does not have the authority to adopt CAIR rules that include a set-aside for renewable energy. Additionally, HB 2481 directed the commission to maintain a NO x set-aside for new units, as defined by 40 CFR Part 96, Subparts AA - HH, equal to 9.5% of the Texas CAIR NO x budget. The commission may not alter the amount of the set-asides provided by statute in the manner suggested by the commenter.

The commission does, however, support the promotion of renewable energy and energy conservation through pollution prevention programs.

MORE STRINGENT CONTROLS

Public Citizen, SEED, Blue Skies Alliance, Lone Star Sierra Club, Environment Texas, and 42 individuals commented that HB 2481 provides the commission the authority in implementing the federal CAIR program to require more stringent NO x and SO 2 controls than those in the federal rules. Entergy, AECT, GCLC, NRG, TXU, TMRA, and SPS commented that HB 2481 does not provide the commission with the authority in implementing the federal CAIR program to impose more stringent NOx and SO 2 control requirements than those required under the federal rule. Public Citizen, SEED, Blue Skies Alliance, DFW Sierra, Lone Star Sierra Club, and 49 individuals commented that the proposed rules should be modified to require more stringent NOx reductions than the federal rules. Entergy, AECT, GCLC, NRG, TXU, TMRA, FPL, and SPS opposed any revisions to the rule imposing more stringent NO x and SO 2 reduction requirements than those required under the federal rule. Public Citizen, SEED, Blue Skies Alliance, and Lone Star Sierra Club requested that the proposed rules be adopted with lower emissions caps and emission rates for NO x and SO 2 , and that NO x emissions from East Texas be capped at no more than 100,000 tons per year and at a rate not to exceed 0.05 pounds of NO x /MMBtu for coal-fired EGUs.

The commission has made no changes in response to these comments. The legislature, during the 79th Legislature, 2005, enacted HB 2481, which requires Texas to participate in the EPA-administered interstate cap and trade program for NOx emissions and annual SO 2 emissions by incorporating the federal CAIR by reference. HB 2481 also provided that its provisions applied only while the federal rules were enforceable and that its provisions did not limit the authority of the commission to implement more stringent emissions control requirements. As indicated in the proposal preamble, the commission interprets these requirements together in order to provide effect to the expressed intent of the legislature. Specifically, the commission continues to interpret the language of new THSC, §382.0173(d) as not restricting existing authority to require further emission control requirements, but not to interfere with, or change, the requirements of the CAIR NO x or SO 2 emission trading programs. The legislature expressed clear intent that the commission implement the CAIR emission trading program by requiring the incorporation by reference of the CAIR program rules as promulgated by EPA, and requiring the use of EPA-specified allocation methodology, with some exceptions for CAIR NO x allowances. Requiring more stringent NO x reductions than required by the federal CAIR would not correspond with the statutory requirement to incorporate the CAIR by reference, which specifies the emission budgets for NO x and SO 2 . Similarly, adopting lower emission caps and emission rates for NO x and SO 2 generally, and providing for a specific cap and emission rate for East Texas NO x emissions would be out of line with the flexibility provided for in the federal CAIR, and thus prescribed by the legislature. The federal CAIR provides flexibility in complying with NO x and SO 2 reduction requirements through the unrestricted banking of excess allowances and the trading of allowances between EGUs in affected CAIR states under common caps. By requiring the commission to incorporate the federal rules by reference, the commission must also incorporate the emission budgets contained in the federal CAIR model trading rules.

Representative Dennis Bonnen and Senator Armbrister commented that the legislature did not intend HB 2481, §2 to be interpreted to allow more stringent emission control requirements in the TCEQ rules adopting the federal CAIR.

The commission appreciates the information provided by Representative Bonnen and Senator Armbrister.

LWV commented that a 90% reduction in NO x and SO 2 is an achievable goal, that public health is of primary importance, and that a 90% reduction in NO x and SO 2 would be more protective than the proposed reductions.

The rules have not been revised in response to this comment. While the commission agrees that 90% reductions in NO x and SO 2 emissions would provide more reductions than proposed, the commission has not assessed whether a 90% reduction in NOx and SO 2 emissions is achievable as part of this rulemaking. HB 2481, 79th Legislature, 2005, specifically directed the commission to adopt and incorporate by reference 40 CFR Part 96, Subparts AA - II and Subparts AAA - III and specified the methodology for the allocation of CAIR NO x allowances. Therefore, the commission does not have the authority to require additional emission reductions from EGUs within the scope of implementing CAIR.

Seventy-six individuals requested that the time line for NO x and SO 2 reductions be accelerated to require reductions from EGUs to be met by 2010. GCLC and TMRA commented that the commission should reject any request to accelerate the time line for complying with the proposed NO x and SO 2 reductions due to the technical and logistical constraints with retrofitting the appropriate control equipment on existing lignite-fired units. GCLC and TMRA further commented that NO x and SO 2 emission reductions that cannot be met with technically feasible and commercially demonstrated technology threaten the continued viability of lignite as a part of the electric generation fuel mix. GCLC and TMRA also commented that suggestions that a 70% NO x and SO 2 reduction can be achieved by 2008 are incorrect. GCLC and TMRA state that in developing the federal rules, EPA determined the CAIR time lines while considering such factors as availability of controls and the logistics associated with retrofitting existing equipment, and specifically projected that it would take at least 3 years to install certain types of pollution control technology.

The rules have not been revised in response to these comments. Under HB 2481, 79th Legislature, 2005, the commission was directed to incorporate by reference 40 CFR Part 96, Subparts AA - II and Subparts AAA - III. The commission must adhere to the time lines established by the EPA in the federal CAIR model trading rule for NO x under Subparts AA - II, and for SO 2 under Subparts AAA - III. Under the federal rules, the CAIR NO x program begins in 2009 and the SO 2 portion begins in 2010. The commission does not have the authority to accelerate these time lines for EGUs.

GCLC commented that compliance with CAIR in Texas will result in a significant additional contribution to air quality from the Texas EGU community, which has already made extraordinary efforts in achieving the lowest state NOx emission rate of any coal burning state. In developing the federal CAIR rules, EPA determined the final CAIR emissions caps while considering several factors, including: performance, applicability, availability, cost effectiveness, and logistics of various available control technologies. GCLC commented that EPA's consideration of these factors in the federal CAIR indicate that suggestions regarding the feasibility of 70% NO x and SO 2 emission reductions by 2008 are not grounded in fact, and are incorrect. Lastly, GCLC notes that EPA estimated that for CAIR Phase I, 39.6 gigawatts (GW) of capacity would need to be retrofitted with flue gas desulfurization and that 23.9 GW would need to be retrofitted with select catalytic reduction; and that for Phase II, 32.4 GW would need to be retrofitted with flue gas desulfurization and 26.6 GW would need to be retrofitted with select catalytic reduction.

The commission has made no change in response to this comment. The commission acknowledges that compliance with CAIR may result in additional emission reductions from Texas EGUs. Based on EPA's predictions, by 2010 Texas EGUs will reduce SO 2 emissions by 31% or 180,000 tons and by 2015 a total of 39% by or 226,000 tons. Texas EGUs are also predicted to reduce NO x by 21% or 44,000 tons by 2009 and by 2015 a total of 25% or 52,000 tons of NO x will be reduced. It is also important to note that since Texas will be participating in the EPA-administered cap and trade program for CAIR, reductions could be higher if EGUs elect to over-control beyond their CAIR budgets or could be less if EGUs choose to purchase CAIR allowances for compliance.

Houston Sierra Club commented that CAIR should be implemented in Texas as specified by the legislature via an incorporation by reference of the federal CAIR model trading rule. However, through the commission's authority to protect public health, welfare, safety, and the environment, the commission should require through future rulemaking further reductions so that the total NOx and SO 2 budget for Texas equates to an 80% to 90% reduction in NO x and SO 2 emissions.

The commission has made no changes in response to this comment. Decisions regarding future rulemaking activities must be properly made in those future actions, after public notice and comment.

DALLAS -FORT WORTH AIR QUALITY

Public Citizen, SEED, Blue Skies Alliance, and Lone Star Sierra Club commented that they disagree with the commission's finding in the proposal rule preamble that there will be no cost to local governments in implementing these rules and that if big emission reductions aren't made here, then far more expensive emissions reductions will have to be made in order to bring the Dallas-Fort Worth area and other nonattainment areas in Texas into attainment with the eight-hour ozone NAAQS, which will shift enormous costs to local governments and their citizens.

The commission has made no change in response to the comment. As discussed elsewhere in this preamble, the legislature has directed the commission to implement the mandatory federal CAIR program. The commission is not required to assess possible indirect consequences, including fiscal implications, for units of local government in its fiscal analysis. The commission did note that "local governments owning EGUs with a nameplate capacity of more than 25 MWe used to produce electricity for sale may experience adverse fiscal implications as a result of the proposed new rules." In addition, the commission notes that the fiscal analysis considers the costs to local governments from administration and enforcement of the proposed rules. Potential future costs to local governments relating to the administration and enforcement of other NO x emission reduction strategies are beyond the scope of this rulemaking.

APSR, CWA, Texas Impact, and 46 individuals requested that the proposed rules be adopted requiring 70% NO x and SO2 reductions in order to assist the Dallas-Fort Worth area in meeting health-based standards for air quality. Public Citizen, SEED, Blue Skies Alliance, DFW Sierra Club, Lone Star Sierra Club, and 45 individuals commented that NO x and SO 2 emissions from coal-fired EGUs in East Texas are impacting attainment of the national ambient air quality standard for ozone in the Dallas-Fort Worth area. Public Citizen further commented that adopting lower CAIR limits (cap on East Texas emissions at no more than 100,000 tons per year and at a rate for coal plants not to exceed .05 pounds per MMBtu) is critical to making progress toward attainment of the eight-hour ozone NAAQS in the Dallas-Fort Worth area, and to providing health benefits in other areas of Texas. Public Citizen provided an analysis of the effect of CAIR reductions on the Dallas-Fort Worth area. Public Citizen also commented that new power plants currently being proposed and the governor's executive order expediting permitting for those plants further complicates the ability to bring the Dallas-Fort Worth area into attainment for the eight-hour ozone NAAQS. Public Citizen commented that if the proposed rules are not modified to assure that air quality is protected, additional and far more costly retrofit will be required of newly permitted plants. Public Citizen commented that the cost per ton of controlling NO x from power plants is approximately $900 to $1,500 per ton, which is possibly one of the least expensive forms of NOx control. Public Citizen commented that Dallas-Fort Worth and other areas are facing loss of federal highway funds and other economic sanctions if they fail to meet clean air standards. Public Citizen provided a presentation to the commission entitled "CAIR Limits Matter." The presentation discussed concerns about DFW air quality and attainment of the national ambient air quality standards. The presentation also focused on putting more stringent controls for NO x in place through CAIR.

The rules have not been revised in response to these comments. The federal CAIR requires upwind states to revise their SIPs to include control measures to reduce emissions of SO 2 and NO x . Reducing upwind precursor emissions will assist downwind PM2.5 and eight-hour ozone nonattainment areas in achieving the PM 2.5 and eight-hour ozone NAAQS. The federal CAIR is specifically intended to address the transport of emissions over the eastern portion of the United States, and its focus is directed at the reduction of upwind precursors, not at the attainment of a local area within Texas, specifically the Dallas-Fort Worth area. The commission is currently developing eight-hour ozone attainment demonstrations for the Dallas-Fort Worth and Houston-Galveston-Brazoria nonattainment areas, that will likely include a number of proposed control measures and will provide opportunity for public comment.

One individual commented with concerns about the episodes chosen for ozone modeling in the DFW area and the wind directions on the specific days that were modeled.

The commission made no changes in response to this comment. The adoption of rules to implement the federal CAIR trading program is independent of SIP development for individual nonattainment areas that must develop SIPs to attain the NAAQS. Ozone attainment modeling concerns are beyond the scope of this rulemaking.

MISCELLANEOUS

EPA suggests clarification of the date for a CAIR NO x source to report a unit's gross electrical output under proposed §101.506(b).

The rules have been revised based on this comment to specify a deadline of July 1, 2011, or July 1 of the control period immediately following the end of the unit's fifth consecutive year of commercial operation, whichever is later. This deadline will provide an adequate amount of time for the CAIR designated representative to submit the relevant data and for the executive director to determine the CAIR NO x allocations from the general NO x trading budget and the new unit set-aside prior to the applicable EPA allocation submittal deadlines.

EPA also provided comments regarding typographical errors. First, on page 1-1, section 1.2 of the CAIR SIP narrative, EPA noted that the proposed language incorrectly identified the citation for the state budgets established under the federal CAIR. Texas must meet the state budget for annual NO x emissions established in 40 CFR §51.123(e)(2) and the state budget for annual SO 2 emissions established in 40 CFR §51.124(e)(2). Second, on page 1 - 2 of the CAIR SIP narrative, the proposed language referenced only 40 CFR Part 96, Subpart AA instead of Subparts AA - II for NO x and Subpart AAA instead of Subparts AAA - III for annual SO 2 emissions. Third, on page 5-5 of the CAIR SIP narrative, the proposed language refers to 40 CFR Part 97, instead of Part 96 for the CAIR designated representative. Lastly, EPA and AECT commented that the proposed rule language under §101.508(a) references 40 CFR §96.140 instead of 40 CFR §96.143.

The commission appreciates the comments and has made changes to reflect the federal CAIR requirements accurately. In addition, the rules have been revised to reference the correct citation to 40 CFR §96.143 under §101.508(a).

AECT commented that the proposed June 1 deadline under §101.504(a)(2) - (4) for the executive director to submit CAIR NO x allocations to EPA should be revised on the basis that historically the Acid Rain data that would be used to determine the proper NO x allocations is not available until well after June 1. AECT recommends revising the submittal deadline to October 31 of each control period as opposed to June 1.

The commission revised the rules based on this comment to require submittal to EPA of CAIR NO x allocations determined under §101.506(c) by October 31. The intent of the proposed rule was to determine CAIR NOx allocations for future control periods based on final data reported to EPA for compliance with the Acid Rain Program. The commission understands that preliminary Acid Rain data is typically available by June 1, however, this data may be revised prior to being finalized. The revision to the rule also provides for consistency between the submittal deadlines under §101.504(a)(1) and (a)(2) - (4).

AECT commented that the proposed rule language under §101.506(b)(2) specifies one method to calculate the baseline heat input for every control period starting with the 2015 control period, while proposed §101.506(b)(3) specifies a different method to calculate baseline heat input for the 2016 control period and for every fifth control period thereafter. AECT notes that either of the two calculation methods could be used to calculate baseline heat input for the 2016 control period and for every fifth control period thereafter and could presumably result in two different baseline heat inputs being calculated for any of those control periods. AECT recommends one of two revisions to correct this situation. Either revise proposed §101.506(b)(1) to apply to the 2009 - 2015 control periods and delete proposed §101.506(b)(2) or revise proposed §101.506(b)(2) to only apply to the 2015 control period. Lastly, AECT comments that HB 2481 does not prohibit these changes, since THSC, §382.0173(c)(1) does not state that the allocation of new units' NO x allowances for the 2015 control period cannot also be made from the special reserve for new units.

The commission has revised the rules based on this comment to delete the phrase "and for every control period thereafter" from proposed §101.506(b)(2). The revised rule specifies a baseline heat input for the 2015 control period for units commencing operation on or after January 1, 2001, and operating for a period of five or more consecutive years, calculated as the average of the three highest amounts of total converted control period heat input over the first five years of operation.

GCLC commented that the proposed NO x allocation methodology accurately implements HB 2481 by setting aside allowances for new sources and requiring reductions from new and existing EGUs but not from other sources. NRG commented that the proposed rules reasonably reflect the emission allocations and time lines specified in the federal CAIR model rule, as directed by HB 2481. Calpine commented that the proposed rules incorporate modifications to the federal CAIR contemplated in HB 2481. TMRA commented that it supports the commission's efforts to adopt state rules that conform to the federal CAIR and that reflect the intent and specific requirements of HB 2481. AECT commented that the proposed rules are consistent overall with the federal CAIR and HB 2481, §2. SPS commented that the proposed rules are consistent with the federal CAIR and HB 2481.

The commission appreciates the support.

SPS requested that the commission include in the adopted rules an express contingency provision to automatically exclude West Texas from CAIR in the event that West Texas is excluded from participation in the federal CAIR program.

The commission has made no change in response to this comment. HB 2481, 79th Legislature, 2005, directed the commission to incorporate by reference the federal CAIR model trading rule and to make permanent allocations that are reflective of the allocation requirements of 40 CFR Part 96, Subpart AA - Subpart HH as issued by EPA on May 12, 2005. These requirements include EGUs from West Texas. HB 2481 directed the commission to "take all reasonable and appropriate steps to exclude West Texas from the federal CAIR rule," . . . "including filing a petition for reconsideration with" EPA (Texas Health and Safety Code, §382.0173(f)). The commission submitted such a Petition for Reconsideration to EPA on July 11, 2005, but EPA denied the petition (See 71 FR 25304 (April 28, 2006)). Meanwhile, the inclusion of West Texas in CAIR has been challenged in federal court by the City of Amarillo and a number of West Texas sources. This challenge has been consolidated with other claims related to CAIR ( See North Carolina et al. v. EPA , Case No. 05-01244 (District of Columbia Circuit)). The commission is not participating in this litigation. While the proposed provision may be consistent with the legislature's intent, and may promptly remove West Texas from the CAIR in the event the pending litigation succeeds or EPA otherwise decides to remove West Texas from the CAIR, there was no opportunity for public notice and comment on this provision. The commission is anticipating further rulemaking, as discussed elsewhere in this preamble, to incorporate changes to the federal CAIR that were recently finalized; and may include such a provision in this future proposal.

Houston Sierra Club commented that the commission should calculate the specific NO x and SO 2 reductions for Texas based on the allocated Phase I and Phase II budgets so that the public can easily understand their significance for the proposed rule. Houston Sierra Club calculated that the NO x budget would require a 16.67% reduction, and the SO 2 budget would require a 30% reduction by Phase II.

The commission appreciates the comment, and acknowledges that the federal CAIR is a complex rule, but has made no changes in response to this comment. Based on the state NO x and SO 2 budgets provided to Texas under the federal CAIR rule, EPA has predicted the NO x and SO 2 reductions associated with CAIR compliance. According to EPA's predictions, CAIR compliance will result in a NO x reduction of 21% in Texas or 44,000 tons by 2009 and a total of 25% or 52,000 tons by 2015. It is also predicted that by 2010 Texas EGUs will reduce SO 2 emissions by 31% or 180,000 tons and by 2015 a total of 39% or 226,000 tons. However, it is important to note that because Texas will be participating in the EPA - administered cap and trade program for CAIR, reductions could be higher if EGUs elect to over-control (reduce emissions greater than necessary for compliance in order to bank allowances for trading purposes) or the reductions could be less if EGUs choose to purchase CAIR allowances to stay in compliance instead of installing controls. Market-based emission cap and trade systems, like the federal CAIR, provide flexibility to comply with emission reduction requirements through unrestricted banking of excess allowances (held by companies that over-control) and trading of allowances (sold by companies that over-control to companies that need to purchase allowances to stay in compliance).

Houston Sierra Club commented that the discussion of the CAIR proposal is difficult to understand and the commission should simplify its explanation of the rule so that the public can understand what is being proposed and the implications of the proposal.

The commission appreciates the comment, and acknowledges that the federal CAIR is a complex rule, but has made no changes in response to this comment. Due to the complexity of the federal CAIR rule, and the requirement under HB 2481 to incorporate the federal CAIR by reference, the adopted rule is also complex. Although the language may be cumbersome, it maintains the continuity of the federal CAIR rule within the state's rules. Information regarding the federal CAIR is available at EPA's Web site, http://www.epa.gov/interstateairquality/ . The commission also has information regarding the federal CAIR and its implementation in Texas available at the TCEQ Web site, http://www.tceq.state.tx.us/implementation/air/sip/caircamr.html .

Houston Sierra Club commented that it is of great concern that the TCEQ is not taking a stronger stand against the harmful effects of particulates, mercury, sulfates and nitrogen oxides; and that it is unacceptable and shameful that two of Texas' most beautiful and magnificent natural landscapes, Big Bend National Park and Guadalupe Mountains National Park too often look like a bad pollution day in Houston.

The commission has made no change in response to this comment. Concerns regarding particulates and mercury are beyond the scope of this rulemaking; and controls on sulfates and nitrogen oxides more stringent than those provided for by the federal CAIR are prohibited by HB 2481, as discussed elsewhere in this response to comments.

LWV and GHASP commented that effects screening levels (ESLs) should be set at enforceable levels based on what is in the airshed now and what might be added in the future in order to protect public health.

The commission made no changes in response to this comment. The adopted rules are designed to implement the federal CAIR program and not to develop ESLs. Nitrogen dioxide and sulfur oxides are currently regulated by federal national ambient air quality standards. Therefore, ESLs are not developed for these compounds.

Seventy-four individuals commented that the announcement of the public hearings for the proposed rulemaking should have been broadcast on local news stations to increase public awareness.

The commission has made no changes in response to this comment. The commission has complied with the requirements for public hearings and notification under 40 CFR §51.102 and §60.23, Texas Government Code, Subchapter B, Chapter 2001, and under THSC, TCAA, §382.017. The commission strives to give all citizens of Texas appropriate prior notification and opportunity to comment, including the ability to submit written comments. Hearing notices for these rules were published in the following newspapers: Austin American-Statesman , March 9, 2006; Corpus Christi Caller-Times , March 8, 2006; El Paso Times , March 8, 2006; Fort Worth Star-Telegram , March 8, 2006; Houston Chronicle , March 8, 2006; and the Midland Reporter-Telegram , March 8, 2006. In addition, on March 9, 2006, a media release was posted to the TCEQ Web site and faxed to radio and television stations and daily and weekly newspapers in the Austin, Dallas-Fort Worth, and Houston markets. The release was also delivered on March 9, 2006, via the media relations listserve, to which anyone may subscribe (see "email alerts" under News Releases on the TCEQ Web site). The commission has no control over the conditions under which media choose to publish or broadcast the content of these releases.

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The new sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.014, concerning emission inventory; §382.016, concerning Monitoring Requirements; HB 2481, §2 of the 79th Legislature, codified at §382.0173, concerning adoption of rules regarding certain SIP requirements and standards of performance for certain sources; and §382.054, concerning federal operating permits; and FCAA, 42 USC, §§7401 et seq ., which requires states to include in their SIPs adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance of, the NAAQS in any other state.

The adopted new sections implement THSC, §§382.002, 382.011, 382.012, 382.014, 382.016, HB 2481, §2 of the 79th Legislature, codified at §382.0173, and §382.054; and FCAA, 42 USC, §§7401 et seq .

§101.504.Timing Requirements for Clean Air Interstate Rule Oxides of Nitrogen Allowance Allocations.

(a) The executive director shall submit to the United States Environmental Protection Agency (EPA) the Clean Air Interstate Rule (CAIR) oxides of nitrogen (NO x ) allowance allocations determined in accordance with §101.506(c) of this title (relating to Clean Air Interstate Rule Oxides of Nitrogen Allowance Allocations) by the following dates:

(1) October 31, 2006, for the 2009 - 2014 control periods;

(2) October 31, 2011, for the 2015 control period;

(3) October 31, 2014, for the 2016 control period; and

(4) 14 months prior to the beginning of each applicable control period for the control period beginning in 2017 and for each control period thereafter.

(b) For the control period beginning in 2009, and for each control period thereafter, the executive director shall submit to EPA the CAIR NO x allowance allocations determined in accordance with §101.506(d) and (e) of this title by October 31 of the applicable control period.

(c) If the executive director fails to submit to EPA the CAIR NO x allowance allocations in accordance with subsection (a) of this section, EPA will assume that the allocations of CAIR NO x allowances for the applicable control period are the same as for the control period that immediately precedes the applicable control period, except that, if the applicable control period is in 2015, EPA will assume that the allocations equal 83% of the allocations for the control period that immediately precedes the applicable control period.

(d) If the executive director fails to submit to EPA the CAIR NO x allowance allocations in accordance with subsection (b) of this section, EPA will assume that no CAIR NO x allowances are to be allocated, for the applicable control period, to any CAIR NO x unit that would otherwise be allocated CAIR NO x allowances under §101.506(d) and (e) of this title.

§101.506.Clean Air Interstate Rule Oxides of Nitrogen Allowance Allocations.

(a) For units commencing operation before January 1, 2001:

(1) for each control period in 2009 - 2015, the baseline heat input, in million British thermal units (MMBtu), is the average of the three highest amounts of the unit's adjusted control period heat input for 2000 - 2004 with the adjusted control period heat input for each year calculated as follows:

(A) if the unit is coal-fired during the year, the unit's control period heat input for such year is multiplied by 90%;

(B) if the unit is natural gas-fired during the year, the unit's control period heat input for such year is multiplied by 50%; and

(C) if the unit is not subject to subparagraph (A) or (B) of this paragraph, the unit's control period heat input for such year is multiplied by 30%.

(2) for the control period beginning January 1, 2016, and for the control period beginning every five years thereafter, the baseline heat input must be adjusted to reflect the average of the three highest amounts of the unit's adjusted control period heat input from control periods one through five of the preceding seven control periods with the adjusted control period heat input for each year calculated as follows:

(A) if the unit is coal-fired during the year, the unit's control period heat input for such year is multiplied by 90%;

(B) if the unit is natural gas-fired during the year, the unit's control period heat input for such year is multiplied by 50%; and

(C) if the unit is not subject to subparagraph (A) or (B) of this paragraph, the unit's control period heat input for such year is multiplied by 30%.

(b) For units commencing operation on or after January 1, 2001:

(1) for each control period in 2009 - 2014, Clean Air Interstate Rule (CAIR) oxides of nitrogen (NO x ) allowances must be allocated from the new unit set-aside identified under §101.503(b) of this title (relating to Clean Air Interstate Rule Oxides of Nitrogen Annual Trading Budget) and determined in accordance with subsection (d) of this section;

(2) for the control period beginning January 1, 2015 for units operating each calendar year during a period of five or more consecutive years, the baseline heat input is the average of the three highest amounts of the unit's total converted control period heat input over the first such five years. The converted control period heat input for each year is calculated as follows:

(A) except as provided in subparagraph (B) or (C) of this paragraph, the converted control period heat input equals the control period gross electrical output of the generator or generators served by the unit multiplied by 7,900 British thermal units per kilowatt-hour (Btu/kWh), if the unit is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-fired for the year, and divided by 1,000,000 Btu/MMBtu. If a generator is served by two or more units, then the gross electrical output of the generator must be attributed to each unit in proportion to the unit's share of the total control period heat input of such units for the year;

(B) for a unit that is a boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the converted heat input is the total heat energy (in Btu) of the steam produced by the boiler during the control period, divided by 0.8 and converted to MMBtu by dividing by 1,000,000 Btu/MMBtu; or

(C) for a unit that is a combustion turbine and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the converted heat input is determined using the equation in the following figure.

Figure: 30 TAC §101.506(b)(2)(C)

(3) for the control period beginning January 1, 2016, and for the control period beginning every five years thereafter, for units operating each calendar year during a period of five or more consecutive years, the baseline heat input shall be adjusted to reflect the average of the three highest amounts of the unit's converted control period heat input from control periods one through five of the preceding seven control periods. The converted control period heat input for each year is calculated as follows:

(A) except as provided in subparagraph (B) or (C) of this paragraph, the converted control period heat input equals the control period gross electrical output of the generator or generators served by the unit multiplied by 7,900 Btu/kWh, if the unit is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-fired for the year, and divided by 1,000,000 Btu/MMBtu, provided that if a generator is served by two or more units, then the gross electrical output of the generator must be attributed to each unit in proportion to the unit's share of the total control period heat input of such units for the year;

(B) for a unit that is a boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the converted control period heat input equals the total heat energy (in Btu) of the steam produced by the boiler during the control period, divided by 0.8 and converted to MMBtu by dividing by 1,000,000 Btu/MMBtu; or

(C) for a unit that is a combustion turbine and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the converted control period heat input is determined using the equation in the following figure.

Figure: 30 TAC §101.506(b)(3)(C)

(c) For units with a baseline heat input calculated under subsection (a) or (b)(2) or (3) of this section, CAIR NO x allowances must be allocated according to the equation in the following figure.

Figure: 30 TAC §101.506(c)

(d) For units commencing operation on or after January 1, 2001, and that have not established a baseline heat input in accordance with subsection (b)(2) or (3) of this section, CAIR NO x allowances must be allocated according to the following.

(1) Beginning with the later of the control period in 2009 or the first control period after the control period in which the CAIR NOx unit commences commercial operation and until the first control period for which the unit is allocated CAIR NO x allowances under subsection (c) of this section, CAIR NO x allowances must be allocated from the new unit set-aside identified under §101.503(b) of this title. For the first control period in which a CAIR NO x unit commences commercial operation, such CAIR NO x unit will not receive a CAIR NOx allocation from the new unit set-aside.

(2) To receive a CAIR NO x allowance allocation from the new unit set-aside, the CAIR designated representative shall submit to the executive director a written request on or before July 1 of the first control period for which the CAIR NO x allowance allocation is requested and after the date that the CAIR NO x unit commences commercial operation.

(3) In a CAIR NO x allowance allocation request under paragraph (2) of this subsection, the amount of CAIR NOx allowances requested for a control period must not exceed the CAIR NO x unit's total tons of NOx emissions reported to EPA for the calendar year immediately preceding such control period.

(4) The executive director shall review each CAIR NO x allowance allocation request submitted in accordance with this subsection and shall allocate CAIR NO x allowances for each control period as follows.

(A) The executive director shall accept a CAIR NO x allowance allocation request only if the request meets, or is adjusted as necessary to meet, the requirements of this subsection.

(B) On or after July 1 of the control period, the executive director shall determine the sum of all accepted CAIR NO x allowance allocation requests for the control period.

(C) If the amount of CAIR NO x allowances in the new unit set-aside for the control period is greater than or equal to the sum under subparagraph (B) of this paragraph, then the executive director shall allocate the full amount of CAIR NO x allowances requested to each CAIR NO x unit covered under a CAIR NO x allowance allocation request that was accepted by the executive director.

(D) If the amount of CAIR NO x allowances in the new unit set-aside for the control period is less than the sum under subparagraph (B) of this paragraph, then the executive director shall allocate CAIR NO x allowances to each CAIR NO x unit covered under a CAIR NO x allowance allocation request accepted by the executive director according to the equation in the following figure.

Figure: 30 TAC §101.506(d)(4)(D)

(E) The executive director shall notify each CAIR designated representative who submitted a CAIR NO x allowance allocation request of the amount of CAIR NO x allowances, if any, allocated for the control period to the CAIR NO x unit covered under the request.

(e) If, after completion of the procedures under subsection (d) of this section for a control period, any unallocated CAIR NO x allowances remain in the new unit set-aside for the control period, the executive director shall allocate to each CAIR NO x unit receiving an allocation under subsection (c) of this section an amount of CAIR NO x allowances equal to the total amount of such remaining unallocated CAIR NO x allowances, multiplied by the unit's allocation under subsection (c) of this section, divided by 90.5% of the NO x trading budget identified in subsection (a) of this section, and rounded to the nearest whole allowance as appropriate.

(f) A unit's control period heat input, and a unit's status as coal-fired or natural gas-fired, for a calendar year under subsection (a) of this section, and a unit's total tons of NO x emissions during a calendar year under subsection (d) of this section, must be determined in accordance with 40 Code of Federal Regulations (CFR) Part 75, to the extent the unit was otherwise subject to the requirements of 40 CFR Part 75 for the year, or must be based on the best available data reported to the executive director for the unit, to the extent the unit was not otherwise subject to the requirements of 40 CFR Part 75 for the year.

(g) On or before the latter of July 1, 2011, or July 1 of the control period immediately following a unit's fifth complete, consecutive year of commercial operation, the CAIR designated representative of a unit establishing a baseline heat input in accordance with subsection (b)(2) or (3) of this section shall submit, on a form specified by the executive director, written certification of the gross electrical output of the generator or generators served by the unit and the total heat energy of any steam produced by the unit during the first five years of commercial operation.

§101.508.Compliance Supplement Pool.

(a) In addition to the Clean Air Interstate Rule (CAIR) oxides of nitrogen (NO x ) allowances allocated under §101.506 of this title (relating to Clean Air Interstate Rule Oxides of Nitrogen Allowance Allocations), the executive director may allocate for the control period in 2009 up to the amount of CAIR NO x allowances listed as the compliance supplement pool for Texas under 40 Code of Federal Regulations (CFR) §96.143.

(b) For any CAIR NO x unit that achieves NO x emission reductions in 2007 and 2008 that are not necessary to comply with any state or federal emissions limitation applicable during such years, the CAIR designated representative of the unit may request early reduction credits and allocation of CAIR NOx allowances from the compliance supplement pool under subsection (a) of this section for such early reduction credits, in accordance with the following.

(1) The owners and operators of such CAIR NO x unit shall monitor and report the NO x emissions rate and the heat input of the unit in accordance with 40 CFR Part 96, Subpart HH for the entire control period for which early reduction credit is requested.

(2) The CAIR designated representative of such CAIR NOx unit shall submit to the executive director by July 1, 2009, a written request for allocation of an amount of CAIR NO x allowances from the compliance supplement pool not exceeding the sum of the amounts, in tons, of the unit's NO x emission reductions in 2007 and 2008 that are not necessary to comply with any state or federal emissions limitation applicable during such years, determined in accordance with 40 CFR Part 96, Subpart HH.

(c) For any CAIR NO x unit whose compliance with the CAIR NO x emissions limitation for the control period in 2009 would create an undue risk to the reliability of electricity supply during such control period, the CAIR designated representative of the unit may request the allocation of CAIR NO x allowances from the compliance supplement pool under subsection (a) of this section, in accordance with the following.

(1) The CAIR designated representative of such CAIR NOx unit shall submit to the executive director by July 1, 2009, a written request for allocation of an amount of CAIR NO x allowances from the compliance supplement pool not exceeding the minimum amount of CAIR NO x allowances necessary to remove such undue risk to the reliability of electricity supply.

(2) In the request under subsection (c)(1) of this section, the CAIR designated representative of such CAIR NO x unit shall demonstrate that, in the absence of allocation to the unit of the amount of CAIR NO x allowances requested, the unit's compliance with CAIR NO x emissions limitation for the control period in 2009 would create an undue risk to the reliability of electricity supply during such control period. This demonstration must include a showing that it would not be feasible for the owners and operators of the unit to:

(A) obtain a sufficient amount of electricity from other electricity generation facilities, during the installation of control technology at the unit for compliance with the CAIR NO x emissions limitation, to prevent such undue risk; or

(B) obtain under subsections (b) and (d) of this section, or otherwise obtain, a sufficient amount of CAIR NO x allowances to prevent such undue risk.

(d) The executive director shall review each request under subsections (b) or (c) of this section submitted by July 1, 2009, and shall allocate CAIR NO x allowances for the control period in 2009 to CAIR NO x units covered by such request as follows.

(1) The executive director shall make any necessary adjustments to the request to ensure that the amount of the CAIR NO x allowances requested meets the requirements of subsections (b) or (c) of this section.

(2) If the total amount of CAIR NO x allowances in all requests, as adjusted under paragraph (1) of this subsection, is less than the amount of allowances in the compliance supplement pool under subsection (a) of this section, the executive director shall allocate to each CAIR NOx unit covered by a request the amount of CAIR NOx allowances requested, as adjusted under paragraph (1) of this subsection.

(3) If the total amount of CAIR NO x allowances in all requests, as adjusted under paragraph (1) of this subsection, is more than the amount of allowances in the compliance supplement pool under subsection (a) of this section, the executive director shall allocate CAIR NO x allowances to each CAIR NO x unit covered by a request according to the equation in the following figure.

Figure: 30 TAC §101.508(d)(3)

(4) By November 30, 2009, the executive director shall determine, and submit to EPA, the allocations under paragraph (2) or (3) of this subsection.

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 July 14, 2006.

TRD-200603754

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-6087

8. CLEAN AIR MERCURY RULE

30 TAC §101.601, §101.602

The Texas Commission on Environmental Quality (TCEQ or commission) adopts new §101.601 and §101.602. Section 101.602 is adopted with changes to the proposed text as published in the March 17, 2006, issue of the Texas Register (31 TexReg 1884). Section 101.601 is adopted without changes to the proposed text and will not be republished.

These new sections are being adopted in Subchapter H, Emissions Banking and Trading, new Division 8, Clean Air Mercury Rule. The new sections will be submitted to the United States Environmental Protection Agency (EPA) as part of the Texas State Plan for the Control of Designated Facilities and Pollutants.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

On May 18, 2005, EPA finalized the clean air mercury rule (CAMR) to permanently cap and reduce mercury emissions from new and existing coal-fired electric generating units (EGUs) nationwide. The mercury reduction requirements under CAMR will be implemented in two phases by providing states with declining budgets. Phase I begins in 2010 and continues through the year 2017. During those years Texas will receive an annual mercury budget of 4.657 tons. The Phase II mercury budget will begin in 2018 and Texas will receive an annual budget of 1.838 tons that year and each year thereafter. EPA provided states with two compliance options for meeting the reduction requirements under CAMR: 1) meet the state's emission budget by requiring new and existing coal-fired EGUs to participate in an EPA-administered cap and trade system; or 2) meet an individual state emissions budget through measures of the state's choosing. During the 79th Legislature, 2005, the legislature enacted House Bill 2481 requiring Texas to participate in the EPA-administered interstate cap and trade program through the incorporation by reference of the CAMR model trading rule.

House Bill (HB) 2481 amended Texas Health and Safety Code (THSC), Chapter 382 by adding 382.0173.THSC, §382.0173(a) requires that the commission adopt rules "incorporat{ing} by reference 40 CFR Subparts AA through II and Subparts AAA through III of Part 96 and 40 CFR Subpart HHHH of Part 60." Additionally, THSC, §382.0173(b) requires the commission to "make permanent allocations that are reflective of the allocation requirements of 40 CFR Subparts AA through HH and Subparts AAA through HHH of Part 96 and 40 CFR Subpart HHHH of Part 60 . . . at no cost . . . using the {EPA's} allocation method as specified by Section 60.4142(a)(1)(I), as issued by that agency on May 12, 2005, or 40 CFR Section 96.142(a)(1)(I), as issued by that agency on May 18, 2005, as applicable with the exception of nitrogen oxides which shall be allocated according to the additional requirements of Subsection (c)." THSC, §382.0173(c) provides additional requirements regarding nitrogen oxides (NO x ) allocations, specifically a requirement to maintain a special reserve of allocations for certain units, and requirements relating to establishing allocations for specific control periods. THSC, §382.0173(d) provided that its provisions applied only while the federal rules were enforceable and that the provisions of House Bill 2481 do "not limit the authority of the commission to implement more stringent emissions control requirements."

The commission interprets these requirements together in order to provide effect to the expressed intent of the legislature. Specifically, the commission interprets the language of new THSC, §382.0173(d) as not restricting existing authority to require further emissions control requirements, but not to interfere with, or change, the requirements of the Clean Air Interstate Rule (CAIR) nitrogen oxides and sulfur dioxide (SO 2 ), or the CAMR mercury emission trading programs. The legislature expressed clear intent that the commission implement the CAIR and CAMR emission trading programs by requiring the incorporation by reference of the CAIR and CAMR program rules as promulgated by EPA, and requiring the use of EPA-specified allocation methodology, with some exceptions for CAIR nitrogen oxides allowances.

The CAMR model trading rule, under 40 Code of Federal Regulations (CFR) Part 60, Subpart HHHH, is a market-based cap and trade system designed to reduce the costs of complying with the new mercury reduction requirements. The Mercury Budget Trading Program caps nationwide annual mercury emissions by providing each state with an annual emissions budget to be applied to all coal-fired boilers and turbines serving an electrical generator with a nameplate capacity greater than 25 megawatts of electricity (MWe) and producing electricity for sale. The trading rule provides flexibility in complying with the mercury reduction requirements through unrestricted banking of excess allowances and the trading of allowances between EGUs nationwide. States participating in the interstate trading program therefore are not subject to individual state caps. Under the model rule, states are provided flexibility in the allocation methodology used to determine mercury allowance allocations for each mercury budget unit. States are then responsible for submitting the allowance allocations to EPA for recordation. Under the CAMR model rule, EPA establishes mercury compliance accounts for each mercury budget source and maintains an allowance tracking system to record the deposit, transfer, and deduction for compliance of all mercury allowances. The mercury budget sources are required, under the model rule, to demonstrate compliance through the installation and operation of continuous emissions monitoring systems as required under 40 CFR Part 75. Finally, the model rule requires all elements of the Mercury Budget Trading Program to be federally enforceable through the issuance of a mercury budget permit as a complete and separable portion of each mercury budget source's Title V permit.

As directed by House Bill 2481, §2 (codified in THSC, §382.0173), the commission is adopting under Subchapter H, new Division 8 of Chapter 101 to incorporate 40 CFR Part 60, Subpart HHHH, by reference for the purpose of complying with the CAMR.

SECTION BY SECTION DISCUSSION

Section 101.601, Applicability

The adopted new §101.601 states that the requirements of Chapter 101, Subchapter H, Division 8, apply to any stationary, coal-fired boiler or stationary, coal-fired combustion turbine meeting the applicability requirements under 40 CFR §60.4104. The referenced applicability requirements under 40 CFR §60.4104 apply to stationary, coal-fired boilers or combustion turbines serving at any time, since the startup of the unit's combustion chamber, a generator with a nameplate capacity of more than 25 MWe producing electricity for sale. The referenced applicability requirements also include cogeneration units serving at any time a generator with nameplate capacity of more than 25 MWe and supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 megawatt-hour (MWh), whichever is greater, to any utility power distribution system for sale.

Section 101.602, Clean Air Mercury Rule Trading Program

The adopted new §101.602 incorporates by reference the CAMR trading program for mercury codified under 40 CFR Part 60, Subpart HHHH, finalized on May 18, 2005. The section requires owners and operators of sources subject to 40 CFR Part 60, Subpart HHHH, to comply with the requirements of that subpart. Based on comment, §101.602(a) was revised to remove the phrase "except as specified in this division" because the additional language is unnecessary since nothing elsewhere in the division contradicts the incorporated federal rule.

The requirements of 40 CFR Part 60, Subpart HHHH, establish the Mercury Budget Trading Program of the CAMR. Specifically, the rules under Subpart HHHH outline a model cap and trade program that may be adopted by states to comply with CAMR. The rules provide for the applicability of the Mercury Budget Trading Program to stationary, coal-fired boilers and combustion turbines serving a generator with a nameplate capacity greater than 25 MWe producing electricity for sale. The Mercury Budget Trading Program provides for an exemption from the program's permitting, monitoring, and reporting requirements for retired units. Retired units continue to receive mercury allowance allocations. The model trading rule outlines standard requirements for each mercury budget source and mercury budget unit, including the requirements to obtain a mercury budget permit; comply with the monitoring, reporting, and recordkeeping requirements of 40 CFR §§60.4170 - 60.4176; and hold mercury allowances not less than the amount of total mercury emissions for each control period, January 1 through December 31 of each calendar year. The requirements under 40 CFR §§60.4110 - 60.4114 describe the procedures for the authorization of a mercury designated representative, the representative's responsibilities, and the responsibilities of both the mercury designated representative and alternate mercury designated representative for a mercury budget source. The mercury designated representative or alternate represents and, through its representations, actions, inactions, or submissions, legally binds each owner and operator of a mercury budget source in all matters pertaining to the Mercury Budget Trading Program. For each mercury budget source required to have a Title V operating permit, 40 CFR §§60.4120 - 60.4124 describe the requirements for each mercury budget source to apply for and obtain a mercury budget permit containing all applicable Mercury Budget Trading Program requirements for each mercury budget unit at the source.

State trading budgets and the methodology and procedures for allocating mercury allowances are provided under 40 CFR §§60.4140 - 60.4142. State budgets are provided in two phases, with Phase I beginning in 2010 and continuing through the year 2017. In each Phase I year, Texas will receive a mercury budget of 4.657 tons. The Phase II mercury budget will begin in 2018, with Texas receiving 1.838 tons in 2018 and each year thereafter. Mercury allowance allocations, in ounces, will be distributed to each mercury budget unit in accordance with the methodology outlined under 40 CFR 60.4142. For units commencing operation before January 1, 2001, mercury allowances are allocated based on the average of the three highest amounts of heat input, in million British thermal units (mmBtu), from calendar years 2000 through 2004 adjusted for the type of coal burned. The coal type adjustment is performed by multiplying the respective portion of the unit's baseline heat input for the year by the following: 3.0 for lignite, 1.25 for subbituminous, and 1.0 for all other coal types. Units commencing operation on or after January 1, 2001, and operating each calendar year for a period of five or more consecutive years will not be eligible for an allocation from the new unit set-aside and will receive their mercury allowance allocation from the general mercury trading budget on a modified output basis. The baseline heat input is the average of the three highest amounts of the unit's total converted control period heat input from the first five years of operation. In calculating a unit's converted control period heat input on a modified output basis, the unit's gross electrical output is multiplied by a heat rate conversion factor of 7,900 British thermal units per kilowatt-hour (Btu/kWh). For cogeneration units, the converted heat input is calculated by converting the available thermal output, in Btu, of useable steam to an equivalent heat input by dividing the thermal output by a general boiler/heat exchanger efficiency of 80%. For combustion turbine cogeneration units, the converted heat input is calculated by converting the available thermal output of useable steam from the heat recovery steam generator or heat exchanger to an equivalent heat input by dividing the thermal output by a general boiler/heat exchanger efficiency of 80%. To this, the electrical generation from the combustion turbine is added after conversion to an equivalent heat input by multiplying the electrical output by 3,413 Btu/kWh. The sum yields the total equivalent heat input for the combustion turbine cogeneration unit.

The model rule provides for each state to set aside a portion of its annual allowance allocation for units newly beginning operation. The model rule allocation methodology allocates a total amount of mercury allowances for the 2010 through 2014 control periods equal to 95% of the Texas mercury trading budget to each mercury budget unit with a baseline heat input determined under 40 CFR §60.4142(a). The allocation will be made in proportion to each mercury budget unit's share of baseline heat input compared to the total baseline heat input for all mercury budget units with a baseline heat input determined under 40 CFR §60.4142(a). Beginning with the 2015 control period, and for each control period thereafter, a total amount of mercury allowances equal to 97% of the mercury trading budget will be allocated to each mercury budget unit with a baseline heat input determined under 40 CFR §60.4142(a) in proportion to each mercury budget unit's share of baseline heat input compared to the total baseline heat input for all mercury budget units with a baseline heat input determined under 40 CFR §60.4142(a).

The model allocation methodology requires the executive director to distribute mercury allowances from the new unit set-aside upon receipt of a request from the mercury budget designated representative for the mercury budget unit. Submittal of each request for a mercury allowance allocation from the new unit set-aside is required on or before July 1 of the first control period for which the request is being made and after the date on which the mercury budget unit commences commercial operation. Mercury allowances requested from the new unit set-aside will not be allocated in excess of the new unit's total tons of mercury emissions reported to EPA for the previous control period. On or after July 1 of each control period, the executive director shall review each mercury allowance allocation request, determine the sum of all such requests, and allocate mercury allowances from the new unit set-aside for the control period. If the amount of mercury allowances in the new unit set-aside is greater than or equal to the sum of all allowances requested, then the executive director shall allocate the amount of mercury allowances requested. If the amount of mercury allowances in the new unit set-aside is less than the sum of all allowances requested, then the executive director shall allocate to each mercury budget unit covered under a request an amount of allowances in proportion to the amount of allowances requested by a mercury budget unit compared to the total amount of allowances requested by all mercury budget units. In the adopted allocation methodology, new units begin receiving allowances from the set-aside for the control period immediately following the control period in which the new unit commences commercial operation, based on the unit's emissions reported for the previous control period. Therefore, a mercury budget source operating a new unit is required to hold allowances covering the emissions from the new unit for the control period in which the new unit commences commercial operation, but will not receive an allocation for that control period. Mercury allowance allocations for a new unit in subsequent control periods will continue to be based on the unit's emissions from the previous control period until the unit establishes a baseline in accordance with 40 CFR §60.4142(a)(1)(ii). All mercury allowance allocations under the adopted allocation methodology are rounded to the nearest whole allowance.

The model rule allows for the distribution of any unallocated mercury allowances remaining in the new unit set-aside for a given control period to mercury budget units with a historical baseline heat input receiving an allocation under 40 CFR §60.4142(b). This distribution is performed by multiplying the amount of unallocated allowances remaining in the set-aside by each mercury budget unit's allocation determined under 40 CFR §60.4142(b), divided by 95% of the Texas mercury trading budget for 2010 to 2014, and divided by 97% for 2015 and thereafter.

The model rule also requires, for the purposes of determining allowance allocations, a mercury budget unit's control period heat input and total ounces of mercury emissions during each calendar year to be determined in accordance with the continuous emission monitoring requirements of 40 CFR Part 75 to the extent that the unit was otherwise subject to those requirements for the year. If a mercury budget unit commencing operation before January 1, 2001, was not otherwise subject to the requirements of 40 CFR Part 75 for any given year, the unit's control period heat input, status as coal-fired or natural gas-fired, and total ounces of mercury emissions during a calendar year will be based on the best available data reported to the executive director. The types and amounts of fuel combusted by such a mercury budget unit will also be based on the best available data reported to the executive director.

The model trading rule requires the executive director to submit to EPA by October 31, 2006, the mercury allowance allocations for the 2010 through 2014 control periods for mercury budget units with a historical baseline heat input determined under 40 CFR §60.4142(a). Subsequently, by October 31, 2008, and October 31 of each year thereafter, the model rule requires submittal to EPA of the mercury allowance allocations for mercury budget units with a historical baseline heat input determined under 40 CFR §60.4142(a) for the control period beginning in the sixth year after the year of the applicable submittal deadline. For example, the mercury allowance allocations determined under 40 CFR §60.4142(a) for the 2015 control period shall be submitted to EPA by October 31, 2008. The model rule also describes the actions EPA may take should the executive director fail to submit the mercury allowance allocations by the applicable deadlines. If the mercury allowance allocations are not provided to EPA by the applicable deadlines in 40 CFR §60.4141(b)(1) for each control period, EPA will assume the mercury allowance allocations for the applicable control period are the same as for the immediately preceding control period. If the applicable control period for which the allowance allocation is not submitted is 2018, EPA will assume the mercury allowance allocations equal the allocations for the 2017 control period multiplied by the state trading budget for Phase II and divided by the state trading budget for Phase I. Finally, by October 31, 2010, and October 31 of each year thereafter, the executive director is required to submit to EPA the mercury allowance allocations distributed from the new unit set-aside under 40 CFR §60.4142(c) and (d) for that control period. If the executive director fails to submit the allowance allocations by the applicable deadline in 40 CFR §60.4141(c)(1) for each control period, EPA will assume that no allowances are to be allocated for the applicable control period to any mercury budget unit that is otherwise receiving an allocation from the new unit set-aside.

The mercury allowance tracking system; methods for establishing compliance accounts and general accounts; the recording of mercury allowance allocations into a mercury budget source's compliance account; the procedures for deducting allowances for compliance; and the banking of mercury allowances are outlined under 40 CFR §§60.4151 - 60.4157. The Mercury Budget Trading Program allows for the unlimited banking of excess allowances. Deductions for compliance are based on the monitoring and reporting requirements under 40 CFR §60.4154 with "penalty" deductions for emissions in excess of the amount of allowances held in a compliance account being equal to three times the number of ounces emitted in excess. The procedures for the submission and recordation of mercury allowance trades are outlined under 40 CFR §§60.4160 - 60.4162. The model rule, under 40 CFR §§60.4170 - 60.4176, requires mercury budget units to meet the continuous emissions monitoring requirements under 40 CFR Part 75 and outlines the initial certification and recertification procedures for monitoring systems, as well as the applicable recordkeeping and reporting requirements.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking in light of the regulatory impact analysis requirements of Texas Government Code, §2001.0225, and determined that it meets the definition of a "major environmental rule" as defined in that statute. A "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 rulemaking does not, however, meet any of the four applicability criteria for requiring a regulatory impact analysis for a major environmental rule, which are listed in Texas Government Code, §2001.0225(a). Texas Government Code, §2001.0225, applies only to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

The adopted rulemaking incorporates by reference the federal CAMR emissions trading rules located in 40 CFR Part 60, Subpart HHHH. 42 United States Code (USC), §7411 creates a system for the establishment of standards of performance to reduce emissions from stationary sources. The CAMR establishes standards of performance for mercury emissions from new and existing coal-fired EGUs. 40 CFR Part 60, Subpart HHHH, creates a trading program for EGUs that will provide a mechanism to meet the mercury standards by capping and then reducing emissions over time. Facilities will demonstrate compliance with the standard by holding one allowance for each ounce of mercury emitted each year. EPA has determined that the cap and trade approach to limiting mercury emissions is the most cost-effective way to achieve reductions. However, states may elect not to participate in the trading program and adopt other strategies to meet their state budgets, which would function as caps in those states. If states choose to participate in the cap and trade program, as has Texas, they must adopt the model rule. The model rule provides an example allowance allocation methodology, which Texas has adopted. The CAMR is designed to achieve initial mercury reductions through implementation of the federal CAIR. The CAIR also imposes cap and trade programs on EGUs that will reduce emissions of sulfur dioxide and oxides of nitrogen. Emission controls installed to comply with CAIR will achieve mercury reductions as a co-benefit during the first phase of the mercury trading program.

This adopted rulemaking fulfills the requirements of House Bill 2481 to incorporate CAMR by reference and to specify the sources to which the trading program is applicable. The incorporation of CAMR will require emission reductions from certain new and existing stationary coal-fired electric utility units, including boilers and combustion turbines, and certain cogeneration units that meet specific applicability criteria. The incorporation of the federal rule is intended to protect the environment and to reduce risks to human health and safety from environmental exposure to mercury. The required emissions reductions are based on controls that are known to be highly cost-effective for EGUs, but the requirements may have adverse impacts on certain utilities, which could be considered a sector of the economy. The exact cost for each unit cannot be predicted, but significant costs to comply with the emission reduction requirements may be expected for at least some units that install or upgrade emission controls or that purchase allowances. The adopted rulemaking may adversely affect in a material way sources in the state that fall under the applicability requirements in the federal rule. The cost and benefits of the CAMR were analyzed by EPA during the federal notice and comment rulemaking for the CAMR. CAMR is a required federal standard, and the ability of states to modify its requirements is limited.

The adopted rulemaking implements the requirements of the Federal Clean Air Act (FCAA). Under 42 USC, §7411(b)(1)(A), EPA must establish a list of stationary source categories that it has determined "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare." 42 USC, §7411(b)(1)(B), then requires EPA to set national standards of performance for new sources within each listed source category. Standards of performance for existing sources of pollutants in the same source categories must then be issued. Under 42 USC, §7411(d), EPA is authorized to promulgate standards of performance that states must adopt through a state implementation plan (SIP)-like process, which requires state rulemaking action followed by review and approval by EPA under 40 CFR Part 60 Subpart B, Adoption and Submittal of State Plans for Designated Facilities.

Under 42 USC, §7411, states such as Texas that have been delegated the authority to enforce the FCAA must enforce performance standards for new and existing sources of mercury emissions. New sources must comply with Standards of Performance for New Stationary Sources (NSPS) for mercury, as promulgated in the CAMR. In addition, new sources will be covered under the mercury cap of the trading program, and will be required to hold allowances equal to their emissions. For existing sources, 42 USC, §7411, requires EPA to "prescribe regulations which shall establish a procedure similar to that provided by section 7410 of this title (SIPs) under which each State shall submit to the Administrator a plan which (A) establishes standards of performance for any existing source for any air pollutant . . . to which a standard of performance under this section would apply if such existing source were a new source, and (B) provides for the implementation and enforcement of such standards of performance." While 42 USC, §7411, like §7410 (SIPs), does not require specific programs, methods, or reductions in order to meet the standard, state plans must include "enforceable emission limitations and other control measures, means or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter," (meaning Chapter 85, Air Pollution Prevention and Control). The provisions of the FCAA recognize that states are in the best position to determine what programs and controls are necessary or appropriate in order to meet emission standards. This flexibility allows states, affected industry, and the public, to collaborate on the best methods for meeting the standards. Even though the FCAA allows states to develop their own programs, this flexibility does not relieve a state from developing a program that meets the requirements of 42 USC, §7411. Thus, while specific measures are not generally required, the emission reductions are required. States are not free to ignore the requirements of 42 USC, §7411, and must develop strategies to assure that the emission standards for new and existing sources are met. Adoption of the federal rule and participation in its emissions cap and trade approach for mercury emissions is the method the state has chosen to achieve those reductions in a flexible and cost-effective manner.

The requirement to provide a fiscal analysis of proposed regulations in the Texas Government Code was amended by Senate Bill 633 during the 75th legislative session. The intent of Senate Bill 633 was to require agencies to conduct a regulatory impact analysis of extraordinary rules. These are identified in the statutory language as major environmental rules that will have a material adverse impact and will exceed a requirement of state law, federal law, or a delegated federal program, or are adopted solely under the general powers of the agency. With the understanding that this requirement would seldom apply, the commission provided a cost estimate for Senate Bill 633 that concluded "based on an assessment of rules adopted by the agency in the past, it is not anticipated that the bill will have significant fiscal implications for the agency due to its limited application." The commission also noted that the number of rules that would require assessment under the provisions of the bill was not large. This conclusion was based, in part, on the criteria set forth in the bill that exempted proposed rules from the full analysis unless the rule was a major environmental rule that exceeded a federal law.

As discussed earlier in this preamble, the FCAA does not always require specific programs, methods, or reductions in order to meet emission standards; thus, states must develop strategies to help ensure that those standards for new and existing sources are met. Because of the ongoing need to address both national ambient air quality standards for criteria pollutants and NSPS and existing source standards for designated pollutants, the commission routinely proposes and adopts SIP rules and 42 USC, §7411 rules. The legislature is presumed to understand this federal scheme. If each rule proposed for inclusion in the SIP or the 42 USC, §7411 plans was considered to be a major environmental rule that exceeds federal law, then every SIP rule and 42 USC, §7411 rule would require the full regulatory impact analysis contemplated by Senate Bill 633. This conclusion is inconsistent with the conclusions reached by the commission in its cost estimate and by the Legislative Budget Board (LBB) in its fiscal notes. Since the legislature is presumed to understand the fiscal impacts of the bills it passes, and that presumption is based on information provided by state agencies and the LBB, the commission believes that the intent of Senate Bill 633 was only to require the full regulatory impact analysis for rules that are extraordinary in nature. While the 42 USC, §7411 rules will have a broad impact, that impact is no greater than is necessary or appropriate to meet the requirements of the FCAA. For these reasons, rules adopted to implement and enforce the federal standards of performance and 42 USC, §7411 state plan fall under the exception in Texas Government Code, §2001.0225(a), because they are required by federal law.

The commission has consistently applied this construction to its rules since this statute was enacted in 1997. Since that time, the legislature has revised the Texas Government Code, but left this provision substantially unamended. It is presumed that "when an agency interpretation is in effect at the time the legislature amends the laws without making substantial change in the statute, the legislature is deemed to have accepted the agency's interpretation." (Central Power & Light Co. v. Sharp , 919 S.W.2d 485, 489 (Tex. App. Austin 1995), writ denied with per curiam opinion respecting another issue , 960 S.W.2d 617 (Tex. 1997); Bullock v. Marathon Oil Co. , 798 S.W.2d 353, 357 (Tex. App. Austin 1990, no writ ). Cf. Humble Oil & Refining Co. v. Calvert , 414 S.W.2d 172 (Tex. 1967); Dudney v. State Farm Mut. Auto Ins. Co. , 9 S.W.3d 884, 893 (Tex. App. Austin 2000); Southwestern Life Ins. Co. v. Montemayor , 24 S.W.3d 581 (Tex. App. Austin 2000, pet. denied ); and Coastal Indust. Water Auth. v. Trinity Portland Cement Div. , 563 S.W.2d 916 (Tex. 1978)).

The commission's interpretation of the regulatory impact analysis requirements is also supported by a change made to the Texas Administrative Procedure Act (APA) by the legislature in 1999. In an attempt to limit the number of rule challenges based upon APA requirements, the legislature clarified that state agencies are required to meet these sections of the APA against the standard of "substantial compliance" (Texas Government Code, §2001.035). The legislature specifically identified Texas Government Code, §2001.0225, as falling under this standard. The commission has substantially complied with the requirements of Texas Government Code, §2001.0225.

The specific intent of the adopted rules is to adopt and incorporate by reference the federal CAMR emissions trading rules, with the objective to protect the environment and to reduce risks to human health. The adopted rules do not exceed a standard set by federal law or exceed an express requirement of state law. No contract or delegation agreement covers the topic that is the subject of this rulemaking. Finally, this rulemaking was not developed solely under the general powers of the agency, but is required by the Texas Clean Air Act, as codified in THSC, §382.0173. Therefore, this rulemaking is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because, although the adopted rules meet the definition of a "major environmental rule," they do not meet any of the four applicability criteria for a major environmental rule.

TAKINGS IMPACT ASSESSMENT

The commission evaluated the adopted rulemaking and performed an assessment of whether Texas Government Code, Chapter 2007, is applicable. The specific purpose of the adopted rulemaking is to incorporate by reference the federal CAMR emissions trading rules, located in 40 CFR Part 60, Subpart HHHH. Subpart HHHH establishes a mercury emissions cap and trade program for new and existing coal-fired EGUs, for which standards of performance have been promulgated under 42 USC, §7411. During the 79th Legislature, 2005, the legislature enacted House Bill 2481, which created a requirement in the Texas Clean Air Act, codified in THSC, §382.0173, to adopt the federal program rules by reference. Texas Government Code, §2007.003(b)(4), provides that Chapter 2007 does not apply to this adopted rulemaking because it is an action reasonably taken to fulfill an obligation mandated by federal law and by state law.

In addition, the commission's assessment indicates that Texas Government Code, Chapter 2007, does not apply to these adopted rules because this is an action that is taken in response to a real and substantial threat to public health and safety; that is designed to significantly advance the health and safety purpose; and that does not impose a greater burden than is necessary to achieve the health and safety purpose. Thus, this action is exempt under Texas Government Code, §2007.003(b)(13). EPA promulgated federal standards of performance for mercury emissions to reduce presently uncontrolled emissions of mercury. The adopted rules will enable Texas to implement the federal cap and trade program and impose its requirements on new and existing EGUs, ultimately ensuring reductions of mercury emissions into the environment. The action will specifically advance the health and safety purpose by reducing mercury levels through an emissions cap and gradual reductions in emissions. The rules specifically target a category of sources with significant mercury emissions, and through the cap and trade program support cost-effective control strategies. Consequently, the adopted rules meet the exemption criteria in Texas Government Code, §2007.003(b)(13). This rulemaking therefore meets the exemptions in Texas Government Code, §2007.003(b)(4) and (13). For these reasons, Chapter 2007 does not apply to this adopted rulemaking.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq .), and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with Texas Coastal Management Program. As required by §281.45(a)(3) and 31 TAC §505.11(b)(2), relating to Actions and Rules Subject to the Coastal Management Program, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and determined that the action is consistent with the applicable CMP goals and policies. The CMP goal applicable to this rulemaking action is the goal to protect, preserve, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas (31 TAC §501.12(l)). No new sources of air contaminants will be authorized and the adopted rules will maintain at least the same level of or increase the level of emissions control. The CMP policy applicable to this rulemaking action is the policy that commission rules comply with federal regulations in 40 CFR, to protect and enhance air quality in the coastal areas (31 TAC §501.32). This rulemaking action complies with 40 CFR Part 60, Standards of Performance for New Stationary Sources. Therefore, in accordance with 31 TAC §505.22(e), the commission affirms that this rulemaking action is consistent with CMP goals and policies.

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

The requirements of 42 USC, §7410, are applicable requirements of 30 TAC Chapter 122. Facilities that are subject to the Federal Operating Permits Program will be required to obtain, revise, reopen, and renew their federal operating permits as appropriate in order to include CAMR.

PUBLIC COMMENT

The commission conducted public hearings on the proposed rules on April 11, 2006, in Austin; April 12, 2006, in Fort Worth; and April 13, 2006, in Houston. During the public comment period, which closed at 5:00 p.m., April 17, 2006, the commission received comments from Association of Electric Companies of Texas, Inc. (AECT); Austin Physicians for Social Responsibility (APSR); Clean Water Action (CWA); Downwinders at Risk Education Fund; Entergy Services Inc. (Entergy); Environment Texas; FPL Group (FPL); Greater Houston Area Smog Prevention (GHASP); Gulf Coast Lignite Coalition (GCLC); League of Women Voters of Texas (LWV); NRG Texas (NRG); Public Citizen; Representative Dennis Bonnen, District 25; Senator Ken Armbrister, District 18; Sierra Club of Dallas-Fort Worth (DFW Sierra Club); Sierra Club - Houston Regional Group (Houston Sierra Club); Southwestern Public Services (SPS); Suez Energy Generation NA, Inc. (SEGNA); Texas Association of Business (TAB); Texas Impact; Texas Mining and Reclamation Association (TMRA); Texas Campaign for the Environment (TCE); The Sustainable Energy and Economic Development Coalition (SEED); TXU Power (TXU); Working Effectively for Clean Air Now (WECAN); and 140 individuals.

NRG supported comments submitted by GCLC; TMRA supported comments submitted by AECT and GCLC; GCLC supported comments submitted by TMRA and AECT; and Entergy and TXU supported comments submitted by AECT.

TXU, Entergy, AECT, and SPS concurred with Representative Bonnen's comments.

RESPONSE TO COMMENTS

MORE STRINGENT CONTROLS

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, LWV, APSR, CWA, Texas Impact, GHASP, and 56 individuals requested that the commission adopt rules more stringent than the federal rules by requiring a 90% reduction in mercury emissions from coal-fired power plants by the year 2010. In addition, the commenters stated that the goal of the commission should be a total phase-out of mercury emissions from utilities. Texas Impact commented that toxic emissions threaten to stifle growth and development in Texas.

The rules have not been revised in response to this comment. Under House Bill 2481, 79th Legislature, 2005, the commission was directed to adopt and incorporate by reference 40 CFR Part 60, Subpart HHHH, thus requiring the commission to allocate the mercury budget as provided under the federal CAMR model trading rule. Therefore, the commission does not have the authority to require additional mercury reductions from coal-fired EGUs in conjunction with implementing CAMR.

Representative Dennis Bonnen and Senator Armbrister commented that the legislature did not intend Section 2 of HB 2481 to be interpreted to allow more stringent emission control requirements in the TCEQ rules adopting the federal CAMR.

The commission appreciates the information provided by Representative Bonnen and Senator Armbrister.

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, CWA, and 127 individuals requested that the timeline for mercury reductions be accelerated to require reductions from EGUs to be met by 2010. GCLC and TMRA commented that the commission should reject any request to accelerate the timeline for complying with the proposed mercury reductions due to the technical and logistical constraints with retrofitting the appropriate control equipment on existing lignite-fired units.

The rules have not been revised in response to this comment. Under House Bill 2481, 79th Legislature, 2005, the commission was provided specific direction to adopt and incorporate by reference 40 CFR Part 60, Subpart HHHH. Based on this legislative directive, the commission must adhere to the timelines established by EPA under the federal CAMR model trading rule for mercury. Under the federal CAMR model trading rule, Phase I mercury reductions will result from NO x and SO 2 controls initially implemented in 2009 and 2010 under the CAIR. The commission does not have the authority to accelerate the timelines for coal-fired EGUs to comply with these emission reduction requirements.

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, LWV, CWA, DFW Sierra Club, and 43 individuals commented that the commission was provided the authority under HB 2481 to implement more stringent mercury controls than those required under the federal rules. SEED commented, and provided information to support its comment, that other states are implementing more stringent mercury standards than is Texas. AECT, Entergy, GCLC, NRG, SPS, TMRA, and TXU commented that HB 2481 does not provide the commission with the authority in implementing the federal CAMR program to impose more stringent mercury control requirements than those required under the federal rule.

The commission has made no changes in response to these comments. The Texas Legislature, during the 79th Legislative Regular Session, 2005, enacted House Bill 2481, which requires the commission to participate in the EPA-administered cap and trade program for mercury by incorporating the federal CAMR by reference. HB 2481 also provided that its provisions applied only while the federal rules were enforceable and that its provisions did not limit the authority of the commission to implement more stringent emissions control requirements. As indicated in the proposal preamble, the commission interprets these requirements together in order to provide effect to the expressed intent of the legislature. Specifically, the commission continues to interpret the language of new THSC, §382.0173(d) as not restricting existing authority to require further emission control requirements, but not to interfere with, or change, the requirements of the CAMR mercury trading program.

The legislature expressed clear intent that the commission implement the CAMR model trading program by requiring the incorporation by reference of the CAMR program rules as promulgated by EPA. Those rules include a mercury allowance allocation methodology in 40 CFR §60.4142 that the commission is adopting as part of the trading program, requiring the use of EPA-specified allocation methodology. Requiring more stringent mercury reductions than required by the federal CAMR would not be in accord with the statutory requirement to incorporate the CAMR by reference, which specifies the emission budget for mercury in 40 CFR §60.4140 in two phases, 2010 - 2017 and 2018 and thereafter. By requiring the commission to incorporate the federal rule by reference, the commission must also incorporate the allocation methodology and the emission budget contained in the federal CAMR in 40 CFR Part 60.

AECT, Entergy, FPL, GCLC, NRG, SPS, TAB, TMRA, and TXU commented in support of the proposed rule and opposed any revisions to the rule imposing more stringent mercury emission requirements than those required under the federal rule. GCLC and TMRA commented that the legislative directive provided to the commission under HB 2481 is grounded in sound science and based on available control technologies. Lignite coals contain high amounts of elemental mercury which is the hardest form of mercury to capture and control. The adoption of mercury reductions that cannot be met through technologically feasible and commercially available controls threatens the viability of lignite as an electric generation fuel. TAB commented that regulatory certainty afforded by adoption of the federal rule in Texas will increase economic development.

The commission appreciates the support. As discussed elsewhere in this preamble, House Bill 2481, 79th Legislature, 2005, specifically directed the commission to adopt and incorporate by reference 40 CFR Part 60, Subpart HHHH, thus requiring the commission to allocate the mercury budget as provided under the federal CAMR rule. Therefore, the commission does not have the authority to require additional mercury reduction requirements for coal-fired EGUs in conjunction with implementing CAMR.

Houston Sierra Club commented that CAMR should be implemented in Texas as specified by the legislature via an incorporation by reference of the federal CAMR model trading rule. However, through the commission's authority to protect public health, welfare, safety, and the environment, the commission should require through future rulemaking further reductions in mercury emissions that result in an 80% to 90% total mercury reduction, with the overall goal being a total phase-out of mercury emissions.

The commission has made no changes in response to this comment. Decisions regarding future rulemaking activities must be properly made in those future actions, after public notice and comment.

HEALTH IMPACTS

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, APSR, DFW Sierra Club, Texas Impact, and 124 individuals commented that the federal CAMR rule is insufficient to protect human health. SEED provided information regarding studies about health effects of mercury. These groups and individuals are specifically concerned about autism and brain development in prenatally exposed children, in addition to other health impacts. One individual noted that it is possible that lower levels of mercury exposure could be toxic, and that, more likely than not, there is no safe blood level of mercury. Stronger protections are recommended.

The commission has made no changes in response to this comment. As discussed elsewhere in this preamble, the adopted rules are designed to implement the federal CAMR program. Exhaustive health effects analyses were conducted as part of the federal rulemaking process that resulted in the CAMR. (See the discussions regarding studies conducted and reviewed by EPA in the proposed and adopted federal rules, links to which may be found at http://www.epa.gov/air/mercuryrule/rule.htm .) These analyses focused on health effects in fetuses, children, and adults. EPA also prepared an analysis of the final rule entitled "Regulatory Impact Analysis of the Final Clean Air Mercury Rule" in which the results of these health effects studies are discussed. Links to this document and to many others containing EPA's public health analyses may be found at http://www.epa.gov/ttn/atw/utility/utiltoxpg.html .

The commission agrees that mercury is a toxin that can lead to neurological deficits in children and adults. However, the levels at which these toxicities occur is significantly above blood mercury levels in the United States. EPA updated the Reference Dose (RfD) for methylmercury in 2001. The RfD is set at a concentration to protect the most sensitive population (developing fetuses) from the most sensitive health effect (neurological deficit) over a lifetime of exposure. To develop the RfD, EPA used an extensive epidemiological study conducted in the Faroe Islands on a group of natives who consume large amounts of fish and whale blubber over a lifetime. The benchmark dose lower limit or BMDL was derived by first identifying a measurable (5%) adverse change that correlated to cord blood mercury levels and then determining the lower 95% limit of this concentration. The National Research Council recommended a BMDL of 58 parts per billion (ppb) mercury in cord blood based on significant effects measured on the Boston Naming Test. The dose was then converted from cord blood levels to ingested maternal levels. Assuming a 1:1 ratio between cord and maternal blood concentrations, this value was calculated to be 1.081 micro grams (µg) mercury/kilogram (kg) body weight/day. This value was then divided by an uncertainty value of 10 to account for variability, including potential differences between cord blood and maternal blood mercury levels and interindividual variability in mercury metabolism, as well as potential long-term effects not yet measured by this study. Ultimately, a value of 0.1 µg mercury/kg body weight/day (5.8 ppb) was set as the RfD to protect against neurological effects over a lifetime. According to the 1999 - 2000 National Health and Nutrition Examination Survey, the average mercury concentration in women of childbearing age (16 - 49 years) is 1.02 ppb, well below the conservative RfD value of 5.8 ppb. Approximately 5 - 8% of women in the United States have blood mercury levels greater than 5.8 ppb. However, very few, if any, women have blood mercury levels above the BMDL of 58 ppb. In addition, no studies to date have shown a causal relationship between mercury exposure and autism incidence. In fact, the only case-control study published in the peer-reviewed literature by Ip, et al . in 2004 indicated no causal relationship between mercury and autism. Therefore, the commission agrees that control of mercury from coal-burning power plants is beneficial, but disagrees that the federal CAMR rule is insufficient to protect human health.

An individual commented that no specific and appropriate public health measures currently exist to evaluate health effects resulting from coal-fired power plants. SEED commented that regional routine testing of fish should be required as part of permitting.

The commission has made no change in response to this comment. The commission agrees that no public health measures are currently underway in Texas to evaluate the health effects of mercury from coal-fired power plants. However, the commission is not authorized to require state hospitals and/or doctors to report specific symptoms or health effects that are potentially related to environmental contaminants. In addition, although correlations may occur between reported symptoms and environmental exposure, no direct causal relationship can be identified.

Compliance with CAMR will be determined according to the monitoring, reporting, recording, and testing requirements of the Acid Rain program, which are outlined and described in both the CAIR and CAMR.

LWV and GHASP commented that ESLs should be set at enforceable levels based on what is in the airshed now and what might be added in the future in order to protect public health.

The commission has made no change in response to this comment. As discussed elsewhere in this preamble, the adopted rules are designed to implement the federal CAMR program and not to develop effects screening levels (ESLs). There is currently an ESL for mercury. The methodology for developing ESLs recently underwent a peer-review process and public comment period. When the methodology is finalized, the current mercury ESL will be reviewed accordingly and will be available for public comment.

TRADING

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, CWA, DFW Sierra Club, Texas Impact, and 45 individuals commented that trading of mercury should be prohibited under the adopted rules, and that the trading of toxics has never before been allowed and should not be allowed with mercury. However, if trading must be allowed, it should be limited to within set regions of the state. Additionally, all parties of such trading should be jointly and severably liable for all emissions violations with financial penalties levied against all facilities of the companies involved in the trade.

The rules have not been revised in response to this comment. As discussed elsewhere in this preamble, the commission was provided specific direction by the legislature under HB 2481 to adopt and incorporate by reference the federal CAMR model trading rules, thus requiring EGUs in Texas to participate in the EPA-administered cap and trade program for mercury. In incorporating by reference the federal trading rules, EPA does not provide states with the flexibility to limit or prohibit interstate trading. Based on legislative direction and the federal rule requirements, the commission does not have the authority to prohibit or limit the trading of mercury allowances under the Mercury Budget Trading Program.

In addition, the federal CAMR model trading rule sets forth a specific penalty for sources that produce emissions in excess of the number of mercury allowances in their compliance account. The penalty provision under the federal CAMR model trading rule requires the deduction of mercury allowances to be allocated in the control period immediately following the exceedance equivalent to three times the number of ounces emitted in excess. This penalty does not preclude formal enforcement action by the commission or financial penalties resulting from such enforcement action. The commission disagrees with the commenter, however, that all parties involved in a trade should be held jointly liable. It is unreasonable to hold the seller of allowances responsible for the actions of another party over which the seller has no operational control.

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, and 45 individuals commented that the proposed cap and trade program will allow utilities to buy their way out of making the required reductions, possibly resulting in no mercury reductions from utilities in Texas, and will result in mercury hot spots. SEED commented that Northeast Texas is a hot spot and that an Ohio study shows that mercury deposition occurs within 400 miles of coal-burning power plants. DFW Sierra Club commented that Texas leads the nation in both global warming and mercury emissions and that Northeast Texas is a hot spot. TCE commented that Texas is one of the worst states for all types of pollution and that the Trinity River is a virtual dead zone. CWA commented that the closer a waterway is to a power plant that discharges mercury, the more likely it is to be impaired with mercury. CWA and Environment Texas commented that numerous waterways in Texas are impaired as indicated by the quantity of mercury in fish tissue. GCLC and TMRA commented that the proposed rule will not result in utility attributable hot spots because the form of mercury found in the lignite coals in Texas, elemental mercury, does not deposit locally. GCLC and TMRA stated that the proposed rules will decrease the mercury deposition in Texas.

The rules have not been revised in response to this comment. As discussed elsewhere in this preamble, the adopted rules are designed to implement the federal CAMR program, as required by statute. A cap and trade program, when properly implemented and enforced, is an effective means of achieving overall emission reductions by encouraging the most cost-effective reductions to be implemented first. In addition, in finalizing the CAMR, EPA has deemed that a cap and trade approach to limiting mercury emission is the most cost-effective way to achieve reductions from the power sector. The commission acknowledges that, under a cap and trade approach, some sources may purchase allowances to comply rather than install additional controls; however, the imposed cap is finite and will require mercury reductions to occur.

In addition, EPA has defined a "utility hot spot" as "a waterbody that is a source of consumable fish with Methylmercury tissue concentrations, attributable solely to utilities, greater than the EPA's Methylmercury water quality criterion of 0.3 mg/kg." Based on this definition, EPA conducted modeling of utility mercury deposition before and after the implementation of both CAIR and CAMR, and concluded that there was no evidence of utility hot spots resulting from implementation of these rules. Concerns about global warming emissions are outside the scope of this rulemaking.

MISCELLANEOUS

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, and Environment Texas commented that affordable control technologies are already available and have been proven effective at reducing mercury emissions, even for lignite-fired utilities. SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, and 44 individuals commented that all new proposed coal-fired power plants should be required to use the latest mercury control technology, including integrated gasification combined cycle (IGCC) technology. Additionally, no new coal-fired power plants should be permitted until rules to require cleaner coal-fired utilities are implemented. SEED commented that mercury controls and continuous emissions monitors should be required from startup for new coal-burning power plants.

The commission has made no changes in response to this comment. The commission is aware of recent pilot tests of several mercury control technologies for lignite-fired utility boilers. In comparison to other coals, however, the mercury content of lignite is typically higher and more variable. Also, the control technologies evaluated had lower mercury removal efficiencies with lignite than with other coals. The commission is not aware of any testing that has shown 90% or higher mercury removal efficiency with lignite. The commission also notes that market-based cap and trade systems provide flexibility in the manner companies comply with emission budgets, instead of specifying particular control technology requirements.

IGCC is a production process designed to generate electric energy and usable thermal energy, not a specific control technology designed to reduce emissions. The commission does not dictate the choice of production processes. The existing permitting process requires a Best Available Control Technology (BACT) review to ensure the use of control technologies that result in cleaner electric generation. The commission does not have the discretion to withhold the issuance of pending permits to require a level of control based on the determination of future BACT. The Texas Clean Air Act requires the commission to issue permits upon a finding that the applicant has met BACT requirements at the time of application. In addition to the emissions limitation imposed by the mercury emissions budget cap, standards of performance for mercury have been finalized in the CAMR. The federal CAIR and CAMR as adopted by Texas require continuous emissions monitoring and controls that reduce mercury emissions for all new coal-fired utilities.

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, APSR, DFW Sierra Club, and 48 individuals commented that by the year 2010 the proposed rules would allow an increase in mercury emissions from 2003 levels.

The commission has made no changes in response to this comment. According to the commission's 2003 Emissions Inventory, the reported mercury emissions from the 36 existing coal-fired EGUs equal 4.9376 tons. The Phase I mercury budget for Texas under CAMR is 4.657 tons. This equates to a decrease of 0.2806 tons annually. Phase I mercury emission reductions will result from implementation of the federal CAIR. The CAMR does not require the implementation of new mercury-specific controls until Phase II begins in 2018.

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, and Environment Texas commented that the economic analysis for the proposed rule is incomplete and does not address the cost to school districts or the economic impacts on bays, estuaries, and the fishing industry. SEED attached to its written comments a copy of the opinion in Reilly v. U.S. EPA , decided April 13, 2006, by the United States District Court in Massachusetts. SEED does not explain how the case supports its comments. SEED submitted information about studies critical of the EPA's economic analysis supporting the CAMR.

The commission has made no changes in response to these comments. Because the Reilly v. U.S. EPA opinion deals with a Freedom of Information Act request for modeling runs performed by EPA in the process of promulgating the CAMR, and because the opinion discusses the EPA's attempt to withhold modeling run information relating to cost studies relevant to CAMR, the commission interprets SEED's comment to relate to inadequacy of the information about cost studies presented by EPA as part of the CAMR. The EPA provided public notice and opportunity for comment during the promulgation of CAMR. The federal CAMR has been adopted as a final rule and concerns about its promulgation are outside the scope of this rulemaking.

Extensive economic analyses were conducted as part of the federal rulemaking process that resulted in the CAMR. (See the discussion in the proposed and adopted federal rules, links to which may be found at http://www.epa.gov/air/mercuryrule/rule.htm .) These analyses focused on benefits and costs of the implementation of the CAMR on the regulated industry, government, business, and the public. EPA also prepared an economic analysis of the final rule entitled "Regulatory Impact Analysis of the Final Clean Air Mercury Rule." Links to this document and to many others containing EPA's economic analyses may be found at http://www.epa.gov/air/mercuryrule/index.html .

The commission also conducted analyses of the costs and benefits of the implementation of the federal rule through its incorporation by reference in Chapter 101. The commission's fiscal analysis indicates that the primary near-term effect of the CAMR will be the benefits of reduced mercury emissions and greater protection of human health and the environment. Generally, both the EPA and state analyses so far have found no significant adverse effects of the CAMR with the exception of additional costs to utilities.

SEED, Public Citizen, TCE, Downwinders at Risk, WECAN, Environment Texas, and one individual commented that the commission has yet to complete its study on mercury, as required under HB 2481, and should do so prior to adopting any rules concerning mercury.

The rules have not been revised in response to this comment. According to the requirements of HB 2481, the commission must report the findings of the mercury study to the Texas Legislature by September 1, 2006. Given the abbreviated amount of time between the effective date of the federal rule and the deadline for the state to complete its rulemaking and state plan for implementation of the CAMR, the study could not be completed prior to proposal and adoption of the state rule incorporating the CAMR by reference. Staff are currently in the process of conducting the study and developing this report.

Seventy-four individuals commented that the announcement of the public hearings for the proposed rule should have been broadcast on local news stations to increase public awareness.

The commission has made no changes in response to this comment. The commission has complied with the requirements for public hearings and notification under 40 Code of Federal Regulations §51.102 and §60.23; Texas Government Code, Subchapter B, Chapter 2001; and under Texas Health and Safety Code, Texas Clean Air Act, §382.017. The commission strives to give all citizens of Texas appropriate prior notification and opportunity to comment, including the ability to submit written comments. Hearing notices for these rules were published in the following newspapers: Austin American-Statesman , March 9, 2006; Corpus Christi Caller-Times , March 8, 2006; El Paso Times , March 8, 2006; Fort Worth Star-Telegram , March 8, 2006; Houston Chronicle , March 8, 2006; and the Midland Reporter-Telegram , March 8, 2006. In addition, on March 9, 2006, a media release was posted to the TCEQ Web site and faxed to radio and television stations and daily and weekly newspapers in the Austin, Dallas-Fort Worth, and Houston markets. The release was also delivered on March 9 via the media relations listserve, to which anyone may subscribe. (See "email alerts" under News Releases on the TCEQ Web site.) The commission has no control over the conditions under which media choose to publish or broadcast the content of these releases.

Two individuals commented that the CAIR and CAMR do not comply with "the rule between the states." SEED commented that the promulgation of the CAIR and CAMR was not accomplished through a "just process." Environment Texas commented that the EPA illegally delisted power plants from the list of sources requiring maximum controls and illegally set up the cap and trade program.

The commission is unsure what is meant by the comment asserting that the federal rules do not comply with the rule between the states; however, the ultimate result of the implementation of CAIR and CAMR will be reductions in mercury emissions from coal-fired utilities nationwide. CAIR and CAMR underwent public notice and comment and have been adopted by the EPA as final rules. Challenges to or concerns about their promulgation are outside the scope of this rulemaking.

One individual commented that the commission should require monitoring of and regulate mercury from gas streams.

The rules have not been revised in response to this comment. The adopted rules are designed to implement the federal CAMR program which applies specifically to coal-fired EGUs. Monitoring of mercury emissions from these sources is a requirement under these rules. Requirements to monitor or regulate mercury emissions from gas processing facilities are outside the scope of this rulemaking and would need to be addressed in a separate, future rulemaking.

Houston Sierra Club commented that the commission should calculate the specific mercury reduction for Texas based on the allocated Phase I and Phase II mercury budgets so that the public can easily understand its significance for the proposed rule.

Under the federal CAMR rule, Texas has been given an annual mercury budget of 4.657 tons for Phase I (2010 - 2017) and 1.838 tons for Phase II (2018 - and thereafter). Based on this budget, EPA predicted the mercury reductions associated with CAMR compliance. According to EPA's predictions, CAMR compliance in Texas will result in a mercury reduction of 7% or 0.4 tons by 2010 and a total of 63% or 3.2 tons by 2018. However, it is important to note that because Texas will be participating in the EPA-administered cap and trade program for CAMR, reductions could be higher if EGUs elect to over-control beyond their CAMR allocations or the reductions could be less if EGUs choose to purchase CAMR allowances to stay in compliance. Regardless of the number of new coal-fired EGUs in Texas, the state's mercury budget will not increase.

AECT recommended revising proposed §101.602(a) to remove the phrase "except as specified in this division" on the basis that the phrase is unnecessary and confusing since there is nothing specified elsewhere in the division that is contrary to the statement made in proposed §101.602(a).

The rule has been revised based on this comment to remove the phrase "except as specified in this division" from §101.602(a). The phrase is unnecessary because there is no language elsewhere in Division 8 that contradicts the language in §101.602(a).

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the Texas Clean Air Act. The new sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.014, concerning Emission Inventory; §382.016, concerning Monitoring Requirements; House Bill 2481, §2, codified in THSC, §382.0173, concerning Adoption of Rules Regarding Certain SIP Requirements and Standards of Performance for Certain Sources; §382.054, concerning Federal Operating Permit; and FCAA, 42 USC, §§7401 et seq ., which requires states to submit plans establishing standards of performance for existing sources of pollutants for which national ambient air quality standards have not been established, and providing for the implementation and enforcement of such standards of performance.

The adopted new sections implement THSC, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.0173, 382.054, and FCAA, 42 USC, §§7401 et seq .

§101.602.Clean Air Mercury Rule Trading Program.

(a) The commission adopts and incorporates by reference the provisions of 40 Code of Federal Regulations (CFR) Part 60, Subpart HHHH, Emission Guidelines and Compliance Times for Coal-Fired Electric Steam Generating Units, as adopted May 18, 2005 (70 FR 28606), for purposes of implementing the clean air mercury rule (CAMR) trading program for mercury to meet the requirements of Federal Clean Air Act, §111.

(b) Owners and operators of sources subject to 40 CFR Part 60, Subpart HHHH, shall comply with those requirements.

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 July 14, 2006.

TRD-200603762

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-5017

Chapter 122. FEDERAL OPERATING PERMITS PROGRAM

The Texas Commission on Environmental Quality (TCEQ or commission) adopts amendments to §§122.10, 122.12, 122.120, and 122.410 and also adopts new §§122.420, 122.422, 122.424, 122.426, 122.428, 122.440, 122.442, 122.444, 122.446, and 122.448.

Sections 122.10, 122.12, 122.120, 122.410, 122.420, 122.422, 122.424, 122.426, 122.428, and 122.444 are adopted with changes to the proposed text as published in the March 17, 2006, issue of the Texas Register (31 TexReg 1891). Sections 122.440, 122.442, 122.446, and 122.448 are adopted without changes and will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

On May 12, 2005, the United States Environmental Protection Agency (EPA) published the Clean Air Interstate Rule (CAIR) to assist nonattainment areas in downwind states in achieving compliance with the national ambient air quality standards (NAAQS) for particulate matter less than or equal to 2.5 microns (PM 2.5 ) and eight-hour ozone. Twenty-eight eastern states and the District of Columbia were identified as upwind contributors to the nonattainment of the PM 2.5 and eight-hour ozone NAAQS, prompting the requirement for the reduction in emissions of sulfur dioxide (SO 2 ) and nitrogen oxides (NO x ). Twenty-three states, including Texas, and the District of Columbia were found to contribute to the downwind nonattainment of the PM 2.5 NAAQS and are required to make reductions in annual emissions of SO 2 and NO x .

On May 18, 2005, EPA published the Clean Air Mercury Rule (CAMR) to permanently cap and reduce mercury emissions from new and existing coal-fired electric generating units (EGUs), nationwide. The mercury reduction requirements under CAMR will be implemented in two phases by providing states with declining budgets. Phase I begins in 2010 and continues through the year 2017. During those years, Texas will receive an annual mercury budget of 4.657 tons. The Phase II mercury budget will begin in 2018, and Texas will receive an annual budget of 1.838 tons that year and each year thereafter.

EPA provided states with two compliance options for meeting the reduction requirements under CAIR and CAMR: 1) meet the state's emission budgets by requiring EGUs to participate in an EPA- administered interstate cap and trade program; or 2) meet an individual state emissions budget through measures of the state's choosing. The 79th Legislature, 2005, enacted House Bill (HB) 2481, requiring Texas to participate in the EPA-administered interstate cap and trade program through the incorporation by reference of the CAIR and CAMR model trading rules. HB 2481 also provided specific direction for the methodology to be used in allocating the CAIR NO x budget provided to Texas, identified an amount of CAIR NO x allowances to be set aside for new sources, and specified that reductions associated with CAIR would only be required from new and existing EGUs and not from other sources of SO 2 and NO x emissions.

The CAIR and CAMR model trading rules under federal regulations are market-based cap and trade systems designed to reduce the costs of complying with the new NO x , SO 2 , and mercury reduction requirements. The CAIR trading programs cap annual emissions of NO x and SO 2 by providing each state in the named region with an annual emissions budget to be applied to all fossil fuel-fired boilers and turbines serving an electrical generator with a nameplate capacity greater than 25 megawatts of electricity (MWe) and producing electricity for sale. The CAMR trading program caps nationwide annual emissions of mercury by providing each state with an annual emissions budget to be applied to all coal-fired boilers and turbines serving an electrical generator with a nameplate capacity greater than 25 MWe and producing electricity for sale.

The commission is concurrently adopting an additional rulemaking to 30 TAC Chapter 101, General Air Quality Rules, in this issue of the Texas Register that will distribute the CAIR and CAMR trading budgets for Texas to each affected unit based on the specific direction provided under HB 2481. The commission is also adopting a CAIR state implementation plan (SIP) and CAMR state plan.

HB 2481 amended Texas Health and Safety Code (THSC), Chapter 382 by adding 382.0173. THSC, §382.0173(a) requires that the commission adopt rules "incorporat{ing} by reference 40 CFR Subparts AA through II and Subparts AAA through III of Part 96 and 40 CFR Subpart HHHH of Part 60." Additionally, THSC, §382.0173(b) requires the commission to "make permanent allocations that are reflective of the allocation requirements of 40 CFR Subparts AA through HH and Subparts AAA through HHH of Part 96 and 40 CFR Subpart HHHH of Part 60 . . . at no cost . . . using the {EPA's} allocation method as specified by Section 60.4142(a)(1)(i), as issued by that agency on May 12, 2005, or 40 CFR Section 96.142(a)(1)(i), as issued by that agency on May 18, 2005, as applicable with the exception of nitrogen oxides which shall be allocated according to the additional requirements of Subsection (c)." THSC, §382.0173(c) provides additional requirements regarding NO x allocations, specifically a requirement to maintain a special reserve of allocations for certain units, and requirements relating to establishing allocations for specific control periods. THSC, §382.0173(d) provided that its provisions applied only while the federal rules were enforceable and that the provisions of HB 2481 do "not limit the authority of the commission to implement more stringent emissions control requirements."

The commission interprets these requirements together in order to provide effect to the expressed intent of the legislature. Specifically, the commission interprets the language of new THSC, §382.0173(d) as not restricting existing authority to require further emissions control requirements, but not to interfere with, or change, the requirements of the CAIR NO x and SO 2 , or the CAMR mercury emission trading programs. The legislature expressed clear intent that the commission implement the CAIR and CAMR emission trading programs by requiring the incorporation by reference of the CAIR and CAMR program rules as promulgated by EPA, and requiring the use of EPA-specified allocation methodology, with some exceptions for CAIR NO x allowances.

Under the EPA model trading rules, each CAIR source and CAMR source must apply for and receive CAIR and CAMR permits as a separate part of the source's federal operating permit. These new and amended sections establish procedures and requirements for incorporating CAIR and CAMR permits into a source's federal operating permit.

CAIR permits may apply to NO x , SO 2 , or both. In rule language applicable to the issuance and administration of CAIR permits, the commission connects elements of the CAIR permit using the conjunction "and." The absence of one of the elements in individual permit circumstances does not affect the applicability of the rule to the remaining elements.

SECTION BY SECTION DISCUSSION

The commission adopts administrative changes throughout these sections to be consistent with Texas Register requirements and other agency rules and guidelines.

§122.10, General Definitions

The amendment adds CAIR and CAMR to the definition of "Applicable requirement."

The commission also deletes §122.10(21)(C) which contains references to 30 TAC Chapters 120, Control of Air Pollution from Hazardous Waste or Solid Waste Management Facilities and 121, Control of Air Pollution from Municipal Solid Waste Management Facilities. These two chapters had been previously repealed. The commission is also modifying the definition of "Major source" to use the term "nitrogen oxides" instead of "oxides of nitrogen" for consistency within this and other commission rules.

§122.12, Acid Rain, Clean Air Interstate Rule, and Clean Air Mercury Rule Definitions

The adopted amendment to this section adds definitions for "Clean Air Interstate Rule permit" and "Mercury budget permit" consistent with the federal definitions in 40 Code of Federal Regulations (CFR) §§60.4102; 96.102; and 96.202, Definitions. In both definitions, the permit is the legally binding and federally enforceable written document specifying annual trading program requirements applicable to the source and to the owner, operator, and designated representative of the source and each unit. The title of the section is amended to "Acid Rain, Clean Air Interstate Rule, and Clean Air Mercury Rule Definitions."

§122.120, Applicability

The amendment adds §122.120(a)(5) - (7) to expand the requirements of Chapter 122 to CAIR NO x , CAIR SO 2 , and mercury budget units required to have a federal operating permit. The commission is also modifying the section to use the term "nitrogen oxides" instead of "oxides of nitrogen" for consistency within this and other commission rules.

§122.410, Operating Permit Interface

This section previously contained language that incorporates by reference, 40 CFR Parts 72, 74, and 76. The amended section incorporates the most recent version of 40 CFR Parts 72, 74, and 76 and additionally incorporates 40 CFR Parts 73, 77, and 78. These federal regulations relate to the implementation of the Acid Rain Program and include the requirements for CAIR and CAMR. 40 CFR Part 78 was inadvertently left out during proposal and was included during adoption.

§122.420, General Clean Air Interstate Rule Annual Trading Program Permit Requirements

The new section establishes the basic requirements for a CAIR permit. A CAIR permit will include sources of NO x and SO2 that are required to have a federal operating permit. The CAIR permit will contain all applicable requirements of the annual trading programs and will be a separable part of the federal operating permit.

The new section also addresses the case of owners of units not required to have a federal operating permit that elect to opt-in to the CAIR program. In this case, the CAIR permit will become a part of the new source review permit.

The new section states that no CAIR permit will be issued until EPA has received a copy of the certificate of representation for the affected source. The certificate of representation identifies the CAIR source and requires the name, address, e-mail address, and phone number of the designated representative for the source. The certificate also identifies the owners and operators of the source. The designated representative is responsible for and must have the authority to carry out the duties of the CAIR trading programs. The commission is also modifying the section to use the term "nitrogen oxides" instead of "oxides of nitrogen" for consistency within this and other commission rules.

§122.422, Submission of Clean Air Interstate Rule Permit Applications

The new section requires the designated representative for any CAIR NOx source and CAIR SO 2 source required to have a federal operating permit to submit a complete CAIR permit application for the source by June 1, 2007, or at least 18 months prior to the date when a new CAIR unit commences operation. The CAIR model rules require a complete CAIR permit application to be submitted to the permitting authority at least 18 months, or such lesser time provided by the permitting authority, prior to the start of the CAIR NO x and SO2 trading programs. Since the CAIR NO x and SO 2 trading programs begin in 2009 and 2010, respectively, applicants would be required under EPA's model rule to submit separate permit applications for CAIR NO x and CAIR SO 2 sources within one year of one another. The permit application submittal deadline of June 1, 2007, exercises the flexibility provided to states within the model rule to coordinate the permit deadlines for CAIR NO x and SO2 sources and requires the submittal of one permit application for both CAIR NO x and CAIR SO2 sources. The commission anticipates the coordination of the permit application submittal dates to be more efficient for both applicants and commission staff. The commission is also modifying the section to use the term "nitrogen oxides" instead of "oxides of nitrogen" for consistency within this and other commission rules.

The new section also requires a new application covering each CAIR source to be submitted by the designated representative in order to renew the CAIR permit.

§122.424, Information Requirements for Clean Air Interstate Rule Permit Applications

The new section establishes content requirements for CAIR applications. The application should identify each CAIR source and unit and will contain the information required under 40 CFR §96.106 and §96.206, Standard Requirements. These sections of the federal regulations address issues that include compliance accounts, allowance trading, and source monitoring. The new section requires a copy of the certificate of representation that is submitted to EPA, under §122.420, to be provided to the executive director. The commission is also modifying the section to use the term "nitrogen oxides" instead of "oxides of nitrogen" for consistency within this and other commission rules.

§122.426, Clean Air Interstate Rule Permit Contents and Term

The new section requires that each CAIR permit contain the same information required in CAIR permit applications under §122.424. Each CAIR permit incorporates the definitions in 40 CFR §96.102 and §96.202 and every allocation, transfer, or deduction of CAIR NO x or CAIR SO 2 allowances. The term of the CAIR permit will be established by the executive director in order to coordinate the renewal of the CAIR permit with the issuance, revision, or renewal of the source's federal operating permit. The commission is also modifying the section to use the term "nitrogen oxides" instead of "oxides of nitrogen" for consistency within this and other commission rules.

§122.428, Clean Air Interstate Rule Permit Revisions

This new section authorizes the executive director to revise CAIR permits as necessary in accordance with the requirements of this chapter.

§122.440, General Mercury Budget Trading Program Permit Requirements

The new section establishes the basic requirements for a mercury budget permit. A mercury budget permit will be issued to sources with a mercury budget that are required to have a federal operating permit. The mercury budget permit will contain all applicable requirements of the annual trading program and will be a separable part of the federal operating permit.

The new section also states that no mercury budget permit will be issued until EPA has received a copy of the certificate of representation for the affected source. The certificate of representation identifies the mercury budget source and requires the name, address, e-mail address, and phone number of the designated representative for the source. The certificate also identifies the owners and operators of the source. The designated representative is responsible for and must have the authority to carry out the duties of the Mercury Budget Trading Program.

§122.442, Submission of Mercury Budget Permit Applications

The new section requires the designated representative for any mercury budget source required to have a federal operating permit to submit a complete mercury budget application for the source by June 1, 2007, or at least 18 months prior to when the new mercury budget source commences operation. The CAMR model rule requires a complete mercury budget permit application to be submitted to the permitting authority at least 18 months, or such lesser time provided by the permitting authority, prior to the start of the Mercury Budget Trading Program. Since the Mercury Budget Trading Program begins in 2010, applicants would be required under EPA's model rule to submit permit applications for mercury budget permits one year after submittal of their application for a CAIR permit. The permit application submittal deadline of June 1, 2007, exercises the flexibility provided to states within the model rule to coordinate the permit deadlines for CAMR and CAIR and requires the submittal of one permit application for the mercury budget, CAIR NO x , and CAIR SO 2 trading programs. The commission anticipates the coordination of the permit application submittal dates to be more efficient for both applicants and commission staff.

The new section also requires that a new application covering each mercury budget source be submitted by the designated representative in order to renew the mercury budget permit.

§122.444, Information Requirements for Mercury Budget Permit Applications

The new section establishes content requirements for mercury budget permit applications. The application must identify each mercury budget source and unit and will contain the information required under 40 CFR §60.4106, Standard Requirements, which addresses issues that include compliance accounts, allowance trading, and source monitoring. The new section requires that a copy of the certificate of representation submitted to EPA under §122.440 be provided to the executive director.

§122.446, Mercury Budget Permit Contents and Term

The new section requires that each mercury budget permit contain the same information required in mercury budget permit applications under §122.444. Each mercury budget permit will incorporate the definitions in 40 CFR §60.4102 and every allocation, transfer, and/or deduction of mercury allowances. The term of the mercury budget permit will be established by the executive director in order to coordinate the permit with the issuance, revision, or renewal of the source's federal operating permit.

§122.448, Mercury Budget Permit Revisions

This new section authorizes the executive director to revise mercury budget permits as necessary in accordance with the requirements of this chapter or other rules concerning permits.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the rulemaking in light of the regulatory impact analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking meets the definition of a "major environmental rule" as defined in that statute. A "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 rulemaking does not, however, meet any of the four applicability criteria for requiring a regulatory impact analysis for a major environmental rule, which are listed in Texas Government Code, §2001.0225(a). Texas Government Code, §2001.0225, applies only to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

The rulemaking is an incorporation by reference of changes relating to the federal Acid Rain Program in addition to requirements for federal operating permits to support CAIR and CAMR. CAIR includes EPA-administered emissions trading programs that will be governed by model rules provided in CAIR, which states may incorporate by reference. EPA found that Texas is among several states that contribute significantly to nonattainment of the NAAQS for PM2.5 in downwind states. EPA is requiring these upwind states to revise their SIPs to include control measures to reduce emissions of SO 2 and NO x , which are precursors to PM 2.5 formation. Reducing upwind precursor emissions will assist downwind PM 2.5 nonattainment areas to achieve the NAAQS in a more equitable, cost-effective manner than if those areas implemented local emissions reductions alone. EPA has specified the amount of each state's required reductions, but states have flexibility to choose the measures by which they achieve them. If states choose to control EGUs, then they must establish a budget or cap for those sources, which will be incorporated into the EGU federal operating permit. 42 United States Code (USC), §7411, creates a system for the establishment of standards of performance to reduce emissions from stationary sources. The CAMR establishes standards of performance for mercury emissions from new and existing coal-fired EGUs. 40 CFR Part 60, Subpart HHHH creates a trading program for EGUs that will provide a mechanism to meet the mercury standards by capping and then reducing emissions over time.

Specifically, the rulemaking incorporates by reference the provisions of 40 CFR Part 72 as published by EPA on May 12, 2005, with an effective date of July 1, 2006; 40 CFR Part 73 as published by EPA on May 12, 2005, with an effective date of July 1, 2006; 40 CFR Part 74 as published by EPA on May 12, 2005, with an effective date of July 1, 2006; 40 CFR Part 76 with an effective date of May 1, 1998, 40 CFR Part 77 as published by EPA on May 12, 2005, with an effective date of July 1, 2006, and 40 CFR Part 78 as published by EPA on May 12, 2005, with an effective date of July 11, 2005, for purposes of implementing an Acid Rain Program that meets the requirements of Federal Clean Air Act (FCAA), Title IV and supports CAIR and CAMR. Additionally, the rulemaking incorporates requirements for federal operating permits for sources subject to CAIR and CAMR. The rulemaking fulfills the requirements of HB 2481, enacted by the 79th Legislature, 2005, to incorporate CAIR and CAMR by reference, which includes requirements for federal operating permits for sources subject to CAIR and CAMR and compliance with the Acid Rain Program.

The incorporation of the federal rules is intended to protect the environment and to reduce risks to human health and safety from environmental exposure by supporting the reductions of NO x and SO2 emissions from upwind states so that downwind states may reach attainment of the NAAQS for PM 2.5 and by reducing emissions of mercury. CAIR includes revisions to the Acid Rain Program regulations under FCAA, Title IV, particularly the regulatory provisions governing the SO 2 cap and trade program. The revisions streamline the operation of the Acid Rain SO 2 cap and trade program and facilitate its interaction with the CAIR trading program. While the rulemaking is intended to protect human health and the environment, it may adversely affect in a material way sources in the state that fall under the applicability requirements in the federal rules. Cost and benefits of CAIR and CAMR were analyzed by EPA during the federal notice and comment rulemaking for CAIR and the CAMR. CAIR and CAMR are required federal programs, and the ability of states to modify their requirements is limited.

The rulemaking implements requirements of the FCAA. Under 42 USC, §7410(a)(2)(D), each SIP must contain adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment of the NAAQS in any other state. While 42 USC, §7410, generally does not require specific programs, methods, or reductions in order to meet the standard, state SIPs must include "enforceable emission limitations and other control measures, means or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter" (42 USC, Chapter 85, Air Pollution Prevention and Control). Under 42 USC, §7411(b)(1)(A), EPA must establish a list of stationary source categories that it has determined "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare." 42 USC, §7411(b)(1)(B), then requires EPA to set national standards of performance for new sources within each listed source category. Standards of performance for existing sources of pollutants in the same source categories must then be issued. Under 42 USC, §7411(d), EPA is authorized to promulgate standards of performance that states must adopt through a SIP-like process, which requires state rulemaking action followed by review and approval by EPA under 40 CFR Part 60, Subpart B, Adoption and Submittal of State Plans for Designated Facilities. One of these requirements is that sources subject to CAIR and CAMR must make appropriate changes to their federal operating permits, and comply with changes to the Acid Rain Program.

The provisions of the FCAA recognize that states are in the best position to determine what programs and controls are necessary or appropriate in order to meet the NAAQS. This flexibility allows states, affected industry, and the public, to collaborate on the best methods for attaining the NAAQS for the specific regions in the state. Even though the FCAA allows states to develop their own programs, this flexibility does not relieve a state from developing a program that meets the requirements of 42 USC, §7410 and §7411. States are not free to ignore the requirements of 42 USC, §7410, and must develop programs to assure that their contributions to nonattainment areas are reduced so that these areas can be brought into attainment on schedule. While 42 USC, §7411, like 42 USC, §7410 (SIPs), does not require specific programs, in order to meet the standard, state plans must include "enforceable emission limitations" and other control measures (including economic incentives such as fees, marketable permits, and auctions of emissions rights). State plans must also include timetables for compliance "as may be necessary or appropriate to meet the applicable requirements of this chapter" (42 USC, Chapter 85). The provisions of the FCAA recognize that states are in the best position to determine what programs and controls are necessary or appropriate in order to meet emission standards. This flexibility allows states, affected industry, and the public, to collaborate on the best methods for meeting the standards. Thus, while specific measures are not generally required, the emission reductions of 42 USC, §7411 are required. States are not free to ignore the requirements of 42 USC, §7411, and must develop strategies to assure that the emission standards for new and existing sources are met. Adoption of the federal CAIR and CAMR and participation in their emissions cap and trade approach for NO x , SO2 , and mercury emissions is the method the state has chosen to achieve those reductions in a flexible and cost-effective manner, and the rules relating to federal operating permits and compliance with the Acid Rain Program requirements are required elements of both CAIR and CAMR.

The requirement to provide a fiscal analysis of proposed regulations in the Texas Government Code was amended by Senate Bill (SB) 633 during the 75th Legislature, 1997. The intent of SB 633 was to require agencies to conduct a regulatory impact analysis of extraordinary rules. These are identified in the statutory language as major environmental rules that will have a material adverse impact and will exceed a requirement of state law, federal law, or a delegated federal program, or are adopted solely under the general powers of the agency. With the understanding that this requirement would seldom apply, the commission provided a cost estimate for SB 633 that concluded "based on an assessment of rules adopted by the agency in the past, it is not anticipated that the bill will have significant fiscal implications for the agency due to its limited application." The commission also noted that the number of rules that would require assessment under the provisions of the bill was not large. This conclusion was based, in part, on the criteria set forth in the bill that exempted proposed rules from the full analysis unless the rule was a major environmental rule that exceeds a federal law.

As discussed earlier in this preamble, the FCAA does not always require specific programs, methods, or reductions in order to meet the NAAQS; thus, states must develop programs for each area contributing to nonattainment to help ensure that those areas will meet the attainment deadlines. Because of the ongoing need to address nonattainment issues, and meet the requirements of 42 USC, §§7410 et seq ., the commission routinely proposes and adopts SIP rules and other federally required rules. The legislature is presumed to understand this federal process. If each rule proposed for inclusion in the SIP or otherwise federally required was considered to be a major environmental rule that exceeds federal law, then every rule would require the full regulatory impact analysis contemplated by SB 633. This conclusion is inconsistent with the conclusions reached by the commission in its cost estimate and by the Legislative Budget Board (LBB) in its fiscal notes. Since the legislature is presumed to understand the fiscal impacts of the bills it passes, and that presumption is based on information provided by state agencies and the LBB, the commission believes that the intent of SB 633 was only to require the full regulatory impact analysis for rules that are extraordinary in nature. While the rules will have a broad impact, that impact is no greater than is necessary or appropriate to meet the requirements of the FCAA. For these reasons, rules adopted for inclusion in the SIP or otherwise federally required fall under the exception in Texas Government Code, §2001.0225(a), because they are required by federal law.

The commission has consistently applied this construction to its rules since this statute was enacted in 1997. Since that time, the legislature has revised the Texas Government Code, but left this provision substantially unamended. It is presumed that "when an agency interpretation is in effect at the time the legislature amends the laws without making substantial change in the statute, the legislature is deemed to have accepted the agency's interpretation." (Central Power & Light Co. v. Sharp , 919 S.W.2d 485, 489 (Tex. App. Austin 1995), writ denied with per curiam opinion respecting another issue , 960 S.W.2d 617 (Tex. 1997); Bullock v. Marathon Oil Co. , 798 S.W.2d 353, 357 (Tex. App. Austin 1990, no writ ). Cf. Humble Oil & Refining Co. v. Calvert , 414 S.W.2d 172 (Tex. 1967); Dudney v. State Farm Mut. Auto Ins. Co. , 9 S.W.3d 884, 893 (Tex. App. Austin 2000); Southwestern Life Ins. Co. v. Montemayor , 24 S.W.3d 581 (Tex. App. Austin 2000, pet. denied ); and Coastal Indust. Water Auth. v. Trinity Portland Cement Div. , 563 S.W.2d 916 (Tex. 1978)).

The commission's interpretation of the regulatory impact analysis requirements is also supported by a change made to the Texas Administrative Procedure Act (APA) by the legislature in 1999. In an attempt to limit the number of rule challenges based upon APA requirements, the legislature clarified that state agencies are required to meet these sections of the APA against the standard of "substantial compliance" (Texas Government Code, §2001.035). The legislature specifically identified Texas Government Code, §2001.0225, as falling under this standard. The commission has substantially complied with the requirements of Texas Government Code, §2001.0225.

The specific intent of the rulemaking is to protect the environment and to reduce risks to human health by adoption of the federal revisions to the Acid Rain Program by reference, and to specify requirements for federal operating permits for sources subject to CAIR and CAMR. The rulemaking does not exceed a standard set by federal law or exceed an express requirement of state law. No contract or delegation agreement covers the topic that is the subject of this rulemaking. Finally, this rulemaking was not developed solely under the general powers of the agency, but is required by THSC, §382.0173. Therefore, this rulemaking is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because, although the rulemaking meets the definition of a "major environmental rule," it does not meet any of the four applicability criteria for a major environmental rule.

TAKINGS IMPACT ASSESSMENT

The commission evaluated the rulemaking and performed an assessment of whether Texas Government Code, Chapter 2007, is applicable. The specific purpose of the rulemaking is an incorporation by reference of changes relating to the federal Acid Rain Program in addition to requirements for federal operating permits to support the federal CAIR and federal CAMR. The 79th Legislature enacted HB 2481, which created a requirement in THSC, TCAA, §382.0173, to adopt the federal CAIR and CAMR program rules by reference, which include requirements relating to the federal Acid Rain Program and federal operating permits. Texas Government Code, §2007.003(b)(4), provides that Texas Government Code, Chapter 2007 does not apply to this rulemaking because it is an action reasonably taken to fulfill an obligation mandated by federal law and by state law.

In addition, the commission's assessment indicates that Texas Government Code, Chapter 2007 does not apply to these rules because this is an action that is taken in response to a real and substantial threat to public health and safety; that is designed to significantly advance the health and safety purpose; and that does not impose a greater burden than is necessary to achieve the health and safety purpose. Thus, this rulemaking action is exempt under Texas Government Code, §2007.003(b)(13). EPA promulgated CAIR to reduce NO x and SO 2 emissions from upwind states so that downwind states may reach attainment of the NAAQS for PM 2.5 . The rulemaking will enable Texas to implement the federal emissions budget and trading program and impose its requirements on new and existing fossil fuel-fired electric utility units, ultimately ensuring reductions of NO x and SO2 emissions. The rulemaking specifically targets a category of sources with significant NO x and SO 2 emissions, and through the cap and trade program supports cost-effective control strategies. EPA also promulgated federal standards of performance for mercury emissions to reduce emissions of mercury. The rulemaking will enable Texas to implement, through the federal operating permit program, the federal cap and trade program and impose its requirements on new and existing coal-fired electric utility units, ultimately ensuring reductions of mercury emissions into the environment. The rulemaking action will specifically advance the health and safety purpose by reducing mercury levels through an emissions cap and gradual reductions in emissions. The rulemaking specifically targets a category of sources with significant mercury emissions, and through the cap and trade program supports cost-effective control strategies.

Consequently, the rulemaking meets the exemption criteria in Texas Government Code, §2007.003(b)(4) and (13). For these reasons, Texas Government Code, Chapter 2007 does not apply to this rulemaking.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq .), and the commission's rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Coastal Management Program. As required by §281.45(a)(3) and 31 TAC §505.11(b)(2), concerning Actions and Rules Subject to the Coastal Management Program, the commission's rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and determined that the action is consistent with the applicable CMP goals and policies. The CMP goal applicable to this rulemaking action is the goal to protect, preserve, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas (31 TAC §501.12(l)). No new sources of air contaminants will be authorized and the revisions will maintain at least the same level of emissions control as the existing rules. The CMP policy applicable to this rulemaking action is the policy that the commission's rules comply with federal regulations in 40 CFR, to protect and enhance air quality in the coastal areas (31 TAC §501.32). This rulemaking action complies with 40 CFR Part 51, Requirements for Preparation, Adoption, and Submittal of Implementation Plans and 40 CFR Part 60, Subpart B, Adoption and Submittal of State Plans for Designated Facilities. Therefore, in accordance with 31 TAC §505.22(e), the commission affirms that this rulemaking action is consistent with CMP goals and policies.

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

The new and amended sections in this adoption are applicable requirements under Chapter 122. Upon the effective date of this rulemaking, owners or operators subject to the Federal Operating Permit Program will be subject to the amended requirements of these sections.

PUBLIC COMMENT

Public hearings for this rulemaking were conducted in Austin on April 11, 2006; in Fort Worth on April 12, 2006; and in Houston on April 13, 2006.

American Wind Energy Association (AWEA), Association of Electric Companies of Texas, Inc. (AECT), Blue Skies Alliance (Blue Skies), Dennis Bonnen, House of Representatives (Bonnen), Calpine Corporation (Calpine), Entergy Services, Inc. (Entergy), FPL Group (FPL), Gulf Coast Lignite Coalition (GCLC), Lone Star Chapter of the Sierra Club (Sierra Club), NRG Texas LP (NRG), Public Citizen, Southwestern Public Service Company (SPS), The Sustainable Energy and Economic Development Coalition (SEED), Texas Mining and Reclamation Association (TMRA), TXU Power (TXU), EPA, and 113 individuals commented during the public comment period. Only those comments concerning issues in Chapter 122 will be addressed in this preamble; the other comments will be addressed in the concurrently adopted amendments to Chapter 101 and SIP narrative.

RESPONSE TO COMMENTS

EPA commented that its revisions to the Acid Rain Program in 40 CFR Parts 72 - 74 made in 2006 should be incorporated in order for the Acid Rain Program to interact with CAIR. EPA suggested changing the preamble discussion for the Chapter 122 rules and the regulatory language for §122.410 to incorporate 40 CFR Part 78.

The commission is adopting by reference 40 CFR Parts 72 - 74 as published in the CAIR final rule on May 12, 2005, with an effective date of July 1, 2006. The commission will consider the incorporation of subsequent amendments to these sections of the federal rules in future rulemaking and SIP revision actions. The commission agrees that 40 CFR Part 78 should be incorporated by reference. This part was mistakenly omitted at proposal of this rule, and the commission has added the appropriate citation in §122.410. The commission is also including reference to 40 CFR Part 78 in the preamble.

EPA stated that the preamble should clarify why §122.10(21)(C) was deleted.

The commission is deleting §122.10(21)(C) because the rule chapters cited in the subparagraph had been repealed in previous rule actions.

Subchapter A. DEFINITIONS

30 TAC §122.10, §122.12

STATUTORY AUTHORITY

The amendments are adopted under Texas Water Code (TWC), §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; HB 2481, §2 of the 79th Legislature, codified at §382.0173, concerning adoption of rules regarding certain SIP requirements and standards of performance for certain sources; and §382.054, concerning federal operating permits; and FCAA, 42 USC, §§7401 et seq ., which require states to include in their SIPs adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance of the NAAQS in any other state.

The adopted amendments implement THSC, §§382.002, 382.011, 382.012, HB 2481, §2 of the 79th Legislature, codified at §382.0173, and §382.054; and FCAA, 42 USC, §§7401 et seq .

§122.10.General Definitions.

The definitions in the Texas Clean Air Act, Chapter 101 of this title (relating to General Air Quality Rules), and Chapter 3 of this title (relating to Definitions) apply to this chapter. In addition, the following words and terms, when used in this chapter, have the following meanings, unless the context clearly indicates otherwise.

(1) Air pollutant--Any of the following regulated air pollutants:

(A) nitrogen oxides;

(B) volatile organic compounds;

(C) any pollutant for which a national ambient air quality standard has been promulgated;

(D) any pollutant that is subject to any standard promulgated under Federal Clean Air Act (FCAA), §111 (Standards of Performance for New Stationary Sources);

(E) unless otherwise specified by the United States Environmental Protection Agency (EPA) by rule, any Class I or II substance subject to a standard promulgated under or established by FCAA, Title VI (Stratospheric Ozone Protection); or

(F) any pollutant subject to a standard promulgated under FCAA, §112 (Hazardous Air Pollutants) or other requirements established under §112, including §112(g), (j), and (r), including any of the following:

(i) any pollutant subject to requirements under FCAA, §112(j). If the EPA fails to promulgate a standard by the date established under FCAA, §112(e), any pollutant for which a subject site would be major shall be considered to be regulated on the date 18 months after the applicable date established under FCAA, §112(e); and

(ii) any pollutant for which the requirements of FCAA, §112(g)(2) have been met, but only with respect to the individual site subject to FCAA, §112(g)(2) requirement.

(2) Applicable requirement--All of the following requirements, including requirements that have been promulgated or approved by the United States Environmental Protection Agency (EPA) through rulemaking at the time of issuance but have future-effective compliance dates:

(A) all of the requirements of Chapter 111 of this title (relating to Control of Air Pollution From Visible Emissions and Particulate Matter) as they apply to the emission units at a site;

(B) all of the requirements of Chapter 112 of this title (relating to Control of Air Pollution from Sulfur Compounds) as they apply to the emission units at a site;

(C) all of the requirements of Chapter 113 of this title (relating to Standards of Performance for Hazardous Air Pollutants and for Designated Facilities and Pollutants), as they apply to the emission units at a site;

(D) all of the requirements of Chapter 115 of this title (relating to Control of Air Pollution from Volatile Organic Compounds) as they apply to the emission units at a site;

(E) all of the requirements of Chapter 117 of this title (relating to Control of Air Pollution From Nitrogen Compounds) as they apply to the emission units at a site;

(F) the following requirements of Chapter 101 of this title (relating to General Air Quality Rules):

(i) Chapter 101, Subchapter A of this title (relating to General Rules), §101.1 of this title (relating to Definitions), insofar as the terms defined in this section are used to define the terms used in other applicable requirements;

(ii) Chapter 101, Subchapter A, §101.3 and §101.10 of this title (relating to Circumvention; and Emissions Inventory Requirements);

(iii) Chapter 101, Subchapter A, §101.8 and §101.9 of this title (relating to Sampling; and Sampling Reports) if the commission or the executive director has requested such action;

(iv) Chapter 101, Subchapter F of this title (relating to Emissions Events and Scheduled Maintenance, Startup, and Shutdown Activities), §§101.201, 101.211, 101.221, 101.222, and 101.223 of this title (relating to Emissions Event Reporting and Recordkeeping Requirements; Scheduled Maintenance, Startup, and Shutdown Reporting and Recordkeeping Requirements; Operational Requirements; Demonstrations; and Actions to Reduce Excessive Emissions); and

(v) Chapter 101, Subchapter H of this title (relating to Emissions Banking and Trading) as it applies to the emission units at a site;

(G) any site-specific requirement of the state implementation plan;

(H) all of the requirements under Chapter 106, Subchapter A of this title (relating to Permits by Rule), or Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) and any term or condition of any preconstruction permit;

(I) all of the following federal requirements as they apply to the emission units at a site:

(i) any standard or other requirement under Federal Clean Air Act (FCAA), §111 (Standards of Performance for New Stationary Sources);

(ii) any standard or other requirement under FCAA, §112 (Hazardous Air Pollutants);

(iii) any standard or other requirement of the Acid Rain, Clean Air Interstate Rule, or Clean Air Mercury Rule Programs;

(iv) any requirements established under FCAA, §504(b) or §114(a)(3) (Monitoring and Analysis or Inspections, Monitoring, and Entry);

(v) any standard or other requirement governing solid waste incineration under FCAA, §129 (Solid Waste Combustion);

(vi) any standard or other requirement for consumer and commercial products under FCAA, §183(e) (Federal Ozone Measures);

(vii) any standard or other requirement under FCAA, §183(f) (Tank Vessel Standards);

(viii) any standard or other requirement under FCAA, §328 (Air Pollution from Outer Continental Shelf Activities);

(ix) any standard or other requirement under FCAA, Title VI (Stratospheric Ozone Protection), unless EPA has determined that the requirement need not be contained in a permit; and

(x) any increment or visibility requirement under FCAA, Title I, Part C or any national ambient air quality standard, but only as it would apply to temporary sources permitted under FCAA, §504(e) (Temporary Sources); and

(J) the following are not applicable requirements under this chapter, except as noted in subparagraph (I)(x) of this paragraph:

(i) any state or federal ambient air quality standard;

(ii) any net ground level concentration limit;

(iii) any ambient atmospheric concentration limit;

(iv) any requirement for mobile sources;

(v) any asbestos demolition or renovation requirement under 40 Code of Federal Regulations (CFR) Part 61, Subpart M (National Emissions Standards for Asbestos);

(vi) any requirement under 40 CFR Part 60, Subpart AAA (Standards of Performance for New Residential Wood Heaters); and

(vii) any state only requirement (including §111.131 of this title (relating to Definitions), §111.133 of this title (relating to Testing Requirements), §111.135 of this title (relating to Control Requirements for Surfaces with Coatings Containing Lead), §111.137 of this title (relating to Control Requirements for Surface Coatings containing less than 1.0% Lead), and §111.139 of this title (relating to Exemptions).

(3) Continuous compliance determination method--For purposes of Subchapter G of this chapter (relating to Periodic Monitoring and Compliance Assurance Monitoring), a method, specified by an applicable requirement, which satisfies the following criteria:

(A) the method is used to determine compliance with an emission limitation or standard on a continuous basis consistent with the averaging period established for the emission limitation or standard; and

(B) the method provides data either in units of the emission limitation or standard or correlated directly with the emission limitation or standard.

(4) Control device--For the purposes of compliance assurance monitoring applicability, specified in §122.604 of this title (relating to Compliance Assurance Monitoring Applicability), the control device definition specified in 40 Code of Federal Regulations Part 64, concerning Compliance Assurance Monitoring, applies.

(5) Deviation--Any indication of noncompliance with a term or condition of the permit as found using compliance method data from monitoring, recordkeeping, reporting, or testing required by the permit and any other credible evidence or information.

(6) Deviation limit--A designated value(s) or condition(s) which establishes the boundary for an indicator of performance. Operation outside of the boundary of the indicator of performance shall be considered a deviation.

(7) Draft permit--The version of a permit available for the 30-day comment period under public announcement or public notice and affected state review. The draft permit may be the same document as the proposed permit.

(8) Emission unit--A discrete or identifiable structure, device, item, equipment, or enclosure that constitutes or contains a point of origin of air pollutants, including appurtenances.

(A) A point of origin of fugitive emissions from individual pieces of equipment, e.g., valves, flanges, pumps, and compressors, shall not be considered an individual emission unit. The fugitive emissions shall be collectively considered as an emission unit based on their relationship to the associated process.

(B) The term may also be used in this chapter to refer to a group of similar emission units.

(C) This term is not meant to alter or affect the definition of the term "unit" for purposes of the Acid Rain Program.

(9) Federal Clean Air Act, §502(b)(10) changes--Changes that contravene an express permit term. Such changes do not include changes that would violate applicable requirements or contravene federally enforceable permit terms and conditions that are monitoring (including test methods), recordkeeping, reporting, or compliance certification requirements.

(10) Final action--Issuance or denial of the permit by the executive director.

(11) General operating permit--A permit issued under Subchapter F of this chapter (relating to General Operating Permits), under which multiple similar stationary sources may be authorized to operate.

(12) Large pollutant-specific emission unit--An emission unit with the potential to emit, taking into account control devices, the applicable air pollutant in an amount equal to or greater than 100% of the amount, in tons per year, required for a source to be classified as a major source, as defined in this section.

(13) Major source--

(A) For pollutants other than radionuclides, any site that emits or has the potential to emit, in the aggregate the following quantities:

(i) ten tons per year (tpy) or more of any single hazardous air pollutant listed under Federal Clean Air Act (FCAA), §112(b) (Hazardous Air Pollutants);

(ii) 25 tpy or more of any combination of hazardous air pollutant listed under FCAA, §112(b); or

(iii) any quantity less than those identified in clause (i) or (ii) of this subparagraph established by the United States Environmental Protection Agency (EPA) through rulemaking.

(B) For radionuclides regulated under FCAA, §112, the term "major source" has the meaning specified by the EPA by rule.

(C) Any site which directly emits or has the potential to emit, 100 tpy or more of any air pollutant. The fugitive emissions of a stationary source shall not be considered in determining whether it is a major source, unless the stationary source belongs to one of the following categories of stationary sources:

(i) coal cleaning plants (with thermal dryers);

(ii) kraft pulp mills;

(iii) portland cement plants;

(iv) primary zinc smelters;

(v) iron and steel mills;

(vi) primary aluminum ore reduction plants;

(vii) primary copper smelters;

(viii) municipal incinerators capable of charging more than 250 tons of refuse per day;

(ix) hydrofluoric, sulfuric, or nitric acid plants;

(x) petroleum refineries;

(xi) lime plants;

(xii) phosphate rock processing plants;

(xiii) coke oven batteries;

(xiv) sulfur recovery plants;

(xv) carbon black plants (furnace process);

(xvi) primary lead smelters;

(xvii) fuel conversion plant;

(xviii) sintering plants;

(xix) secondary metal production plants;

(xx) chemical process plants;

(xxi) fossil-fuel boilers (or combination thereof) totaling more than 250 million British thermal units (Btu) per hour heat input;

(xxii) petroleum storage and transfer units with a total storage capacity exceeding 300,000 barrels;

(xxiii) taconite ore processing plants;

(xxiv) glass fiber processing plants;

(xxv) charcoal production plants;

(xxvi) fossil fuel-fired steam electric plants of more than 250 million Btu per hour heat input; or

(xxvii) any stationary source category regulated under FCAA, §111 (Standards of Performance for New Stationary Sources) or §112 for which the EPA has made an affirmative determination under FCAA, §302(j) (Definitions).

(D) Any site, except those exempted under FCAA, §182(f) (NO x Requirements), which, in whole or in part, is a major source under FCAA, Title I, Part D (Plan Requirements for Nonattainment Areas), including the following:

(i) any site with the potential to emit 100 tpy or more of volatile organic compounds (VOC) or nitrogen oxides (NO x ) in any ozone nonattainment area classified as "marginal or moderate";

(ii) any site with the potential to emit 50 tpy or more of VOC or NO x in any ozone nonattainment area classified as "serious";

(iii) any site with the potential to emit 25 tpy or more of VOC or NO x in any ozone nonattainment area classified as "severe";

(iv) any site with the potential to emit ten tpy or more of VOC or NO x in any ozone nonattainment area classified as "extreme";

(v) any site with the potential to emit 100 tpy or more of carbon monoxide (CO) in any CO nonattainment area classified as "moderate";

(vi) any site with the potential to emit 50 tpy or more of CO in any CO nonattainment area classified as "serious";

(vii) any site with the potential to emit 100 tpy or more of inhalable particulate matter (PM-10) in any PM-10 nonattainment area classified as "moderate";

(viii) any site with the potential to emit 70 tpy or more of PM-10 in any PM-10 nonattainment area classified as "serious"; and

(ix) any site with the potential to emit 100 tpy or more of lead in any lead nonattainment area.

(E) The fugitive emissions of a stationary source shall not be considered in determining whether it is a major source under subparagraph (D) of this paragraph, unless the stationary source belongs to one of the categories of stationary sources listed in subparagraph (C) of this paragraph.

(F) Any temporary source which is located at a site for less than six months shall not affect the determination of a major source for other stationary sources at a site under this chapter or require a revision to the existing permit at the site.

(G) Emissions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not the units are in a contiguous area or under common control, to determine whether the units or stations are major sources under subparagraph (A) of this paragraph.

(14) Notice and comment hearing--Any hearing held under this chapter. Hearings held under this chapter are for the purpose of receiving oral and written comments regarding draft permits.

(15) Permit or federal operating permit--

(A) any permit, or group of permits covering a site, that is issued, renewed, or revised under this chapter; or

(B) any general operating permit issued, renewed, or revised by the executive director under this chapter.

(16) Permit anniversary--The date that occurs every 12 months after the initial permit issuance, the initial granting of the authorization to operate, or renewal.

(17) Permit application--An application for an initial permit, permit revision, permit renewal, permit reopening, general operating permit, or any other similar application as may be required.

(18) Permit holder--A person who has been issued a permit or granted the authority by the executive director to operate under a general operating permit.

(19) Permit revision--Any administrative permit revision, minor permit revision, or significant permit revision that meets the related requirements of this chapter.

(20) Potential to emit--The maximum capacity of a stationary source to emit any air pollutant under its physical and operational design or configuration. Any certified registration established under §106.6 of this title (relating to Registration of Emissions), §116.611 of this title (relating to Registration to Use a Standard Permit), or §122.122 of this title (relating to Potential to Emit), or a permit by rule under Chapter 106 of this title (relating to Permits by Rule) or other new source review permit under Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) restricting emissions or any physical or operational limitation on the capacity of a stationary source to emit an air pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation is enforceable by the United States Environmental Protection Agency. This term does not alter or affect the use of this term for any other purposes under the Federal Clean Air Act (FCAA), or the term "capacity factor" as used in Acid Rain provisions of the FCAA or the Acid Rain rules.

(21) Preconstruction authorization--Any authorization to construct or modify an existing facility or facilities under Chapter 106 and Chapter 116 of this title (relating to Permits by Rule; and Control of Air Pollution by Permits for New Construction or Modification). In this chapter, references to preconstruction authorization will also include the following:

(A) any requirement established under Federal Clean Air Act (FCAA) , §112(g) (Modifications); and

(B) any requirement established under FCAA, §112(j) (Equivalent Emission Limitation by Permit).

(22) Predictive emission monitoring system--A system that uses process and other parameters as inputs to a computer program or other data reduction system to produce values in terms of the applicable emission limitation or standard.

(23) Proposed permit--The version of a permit that the executive director forwards to the United States Environmental Protection Agency for a 45-day review period. The proposed permit may be the same document as the draft permit.

(24) Provisional terms and conditions--Temporary terms and conditions, established by the permit holder for an emission unit affected by a change at a site, or the promulgation or adoption of an applicable requirement or state-only requirement, under which the permit holder is authorized to operate prior to a revision or renewal of a permit or prior to the granting of a new authorization to operate.

(A) Provisional terms and conditions will only apply to changes not requiring prior approval by the executive director.

(B) Provisional terms and conditions shall not authorize the violation of any applicable requirement or state-only requirement.

(C) Provisional terms and conditions shall be consistent with and accurately incorporate the applicable requirements and state-only requirements.

(D) Provisional terms and conditions for applicable requirements and state-only requirements shall include the following:

(i) the specific regulatory citations in each applicable requirement or state-only requirement identifying the emission limitations and standards;

(ii) the monitoring, recordkeeping, reporting, and testing requirements associated with the emission limitations and standards identified under clause (i) of this subparagraph; and

(iii) where applicable, the specific regulatory citations identifying any requirements that no longer apply.

(25) Renewal--The process by which a permit or an authorization to operate under a general operating permit is renewed at the end of its term under §§122.241, 122.501, or 122.505 of this title (relating to Permit Renewals; General Operating Permits; or Renewal of the Authorization to Operate Under a General Operating Permit).

(26) Reopening--The process by which a permit is reopened for cause and terminated or revised under §122.231 of this title (relating to Permit Reopenings).

(27) Site--The total of all stationary sources located on one or more contiguous or adjacent properties, which are under common control of the same person (or persons under common control). A research and development operation and a collocated manufacturing facility shall be considered a single site if they each have the same two-digit Major Group Standard Industrial Classification (SIC) code (as described in the Standard Industrial Classification Manual , 1987) or the research and development operation is a support facility for the manufacturing facility.

(28) State-only requirement--Any requirement governing the emission of air pollutants from stationary sources that may be codified in the permit at the discretion of the executive director. State-only requirements shall not include any requirement required under the Federal Clean Air Act or under any applicable requirement.

(29) Stationary source--Any building, structure, facility, or installation that emits or may emit any air pollutant. Nonroad engines, as defined in 40 Code of Federal Regulations Part 89 (Control of Emissions from New and In-use Nonroad Engines), shall not be considered stationary sources for the purposes of this chapter.

§122.12.Acid Rain, Clean Air Interstate Rule, and Clean Air Mercury Rule Definitions.

The following words and terms, when used in this chapter, have the following meanings, unless the context clearly indicates otherwise.

(1) Acid Rain permit--The legally binding and segregable portion of the federal operating permit issued under this chapter, including any permit revisions, specifying the Acid Rain Program requirements applicable to an affected source, to each affected unit at an affected source, and to the owners and operators and the designated representative of the affected source or the affected unit.

(2) Acid Rain Program--The national sulfur dioxide and nitrogen oxides air pollution control and emissions reduction program established in accordance with Federal Clean Air Act , Title IV, contained in 40 Code of Federal Regulations Parts 72 - 78.

(3) Clean Air Interstate Rule permit--The legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under 40 Code of Federal Regulations Part 96, Subpart CC or Subpart CCC, including any permit revisions, specifying the Clean Air Interstate Rule (CAIR) Nitrogen Oxides (NO x ) Annual Trading Program and CAIR Sulfur Dioxide (SO 2 ) Trading Program requirements applicable to a CAIR NO x source and CAIR SO 2 source, to each CAIR NO x unit and CAIR SO 2 unit at the source, and to the owners and operators and the CAIR designated representative of the source and each such unit.

(4) Designated representative--The responsible individual authorized by the owners and operators of an affected source and of all affected units at the site, as evidenced by a certificate of representation submitted in accordance with the Acid Rain Program, to represent and legally bind each owner and operator, as a matter of federal law, in matters pertaining to the Acid Rain Program. Such matters include, but are not limited to: the holdings, transfers, or dispositions of allowances allocated to a unit; and the submission of or compliance with Acid Rain permits, permit applications, compliance plans, emission monitoring plans, continuous emissions monitor (CEM), and continuous opacity monitor (COM) certification notifications, CEM and COM certification and applications, quarterly monitoring and emission reports, and annual compliance certifications. Whenever the term "responsible official" is used in this chapter, it shall refer to the "designated representative" with regard to all matters under the Acid Rain Program.

(5) Mercury budget permit--The legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under 40 Code of Federal Regulations §§60.4120 - 60.4124, including any permit revisions, specifying the Mercury Budget Trading Program requirements applicable to a mercury budget source, to each mercury budget unit at the source, and to the owners and operators and the mercury designated representative of the source and each such unit.

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 July 14, 2006.

TRD-200603755

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-6087

Subchapter B. PERMIT REQUIREMENTS

1. GENERAL REQUIREMENTS

30 TAC §122.120

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; HB 2481, §2 of the 79th Legislature, codified at §382.0173, concerning adoption of rules regarding certain SIP requirements and standards of performance for certain sources; and §382.054, concerning federal operating permits; and FCAA, 42 USC, §§7401 et seq ., which require states to include in their SIPs adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance of, the NAAQS in any other state.

The adopted amendment implements THSC, §§382.002, 382.011, 382.012, HB 2481, §2 of the 79th Legislature, codified at §382.0173, and §382.054; and FCAA, 42 USC, §§7401 et seq .

§122.120.Applicability.

(a) Except as identified in subsection (b) of this section, owners and operators of one or more of the following are subject to the requirements of this chapter:

(1) any site that is a major source as defined in §122.10 of this title (relating to General Definitions);

(2) any site with an affected unit as defined in 40 Code of Federal Regulations Part 72 subject to the requirements of the Acid Rain Program;

(3) any solid waste incineration unit required to obtain a permit under Federal Clean Air Act (FCAA), §129(e) (relating to Solid Waste Combustion);

(4) any site that is a non-major source which the United States Environmental Protection Agency (EPA), through rulemaking, has designated as no longer exempt or no longer eligible for a deferral from the obligation to obtain a permit. For the purposes of this chapter, those sources may be any of the following:

(A) any non-major source so designated by the EPA, and subject to a standard, limitation, or other requirement under FCAA, §111 (relating to Standards of Performance for New Stationary Sources);

(B) any non-major source so designated by the EPA, and subject to a standard or other requirement under FCAA, §112 (relating to Hazardous Air Pollutants), except for FCAA, §112(r) (relating to Prevention of Accidental Releases); or

(C) any non-major source in a source category designated by the EPA;

(5) any Clean Air Interstate Rule (CAIR) nitrogen oxides unit, as defined in 40 CFR §96.102, Definitions, if the CAIR nitrogen oxides unit is otherwise required to have a federal operating permit;

(6) any CAIR sulfur dioxide unit, as defined in 40 CFR §96.202, Definitions, if the CAIR sulfur dioxide unit is otherwise required to have a federal operating permit; or

(7) any mercury budget unit, as defined in 40 CFR §60.4102, if the mercury budget unit is otherwise required to have a federal operating permit.

(b) The following are not subject to the requirements of this chapter:

(1) any site that is a non-major source which the EPA, through rulemaking, has designated as exempt from the obligation to obtain a permit; or

(2) any site that is a non-major source which the EPA has allowed permitting authorities to defer from the obligation to obtain a permit.

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 July 14, 2006.

TRD-200603756

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-6087

Subchapter E. ACID RAIN PERMITS, CLEAN AIR INTERSTATE RULE, CLEAN AIR MERCURY RULE

1. ACID RAIN PERMITS

30 TAC §122.410

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; HB 2481, §2 of the 79th Legislature, codified at §382.0173, concerning adoption of rules regarding certain SIP requirements and standards of performance for certain sources; and §382.054, concerning federal operating permits; and FCAA, 42 USC, §§7401 et seq ., which require states to include in their SIPs adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance of, the NAAQS in any other state.

The adopted amendment implements THSC, §§382.002, 382.011, 382.012, HB 2481, §2 of the 79th Legislature, codified at §382.0173, and §382.054; and FCAA, 42 USC, §§7401 et seq .

§122.410.Operating Permit Interface.

(a) The commission hereby adopts and incorporates by reference, except as specified in this section, the provisions of 40 Code of Federal Regulations (CFR) Part 72 with an effective date of July 1, 2006; 40 CFR Part 73 with an effective date of July 1, 2006; 40 CFR Part 74 with an effective date of July 1, 2006, Part 76 with an effective date of May 1, 1998; 40 CFR Part 77 with an effective date of July 1, 2006; and 40 CFR Part 78 with an effective date of July 11, 2005, for purposes of implementing an Acid Rain Program that meets the requirements of Federal Clean Air Act, Title IV.

(b) Applicants for sources subject to 40 CFR Parts 72 - 74, 76, and 77 shall comply with those requirements.

(c) If the provisions of 40 CFR Parts 72 - 74, 76, and 77 conflict with or are not included in this chapter, the provisions of 40 CFR Parts 72 - 74, 76, and 77 shall apply and take precedence except for the following.

(1) References to 40 CFR Part 70 in 40 CFR Parts 72 - 74, 76, and 77 shall be satisfied by the requirements of this chapter for the purposes of implementing the Acid Rain Program.

(2) The procedural requirements for Acid Rain permit revisions in 40 CFR Part 72, Subpart H (Acid Rain Permit Revisions) shall be satisfied by §122.414 of this title (relating to Acid Rain Permit Revisions).

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 July 14, 2006.

TRD-200603757

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-6087

2. CLEAN AIR INTERSTATE RULE

30 TAC §§122.420, 122.422, 122.424, 122.426, 122.428

STATUTORY AUTHORITY

The new sections are adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The new sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; HB 2481, §2 of the 79th Legislature, codified at §382.0173, concerning adoption of rules regarding certain SIP requirements and standards of performance for certain sources; and §382.054, concerning federal operating permits; and FCAA, 42 USC, §§7401 et seq ., which require states to include in their SIPs adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance of, the NAAQS in any other state.

The adopted new sections implement THSC, §§382.002, 382.011, 382.012, HB 2481, §2 of the 79th Legislature, codified at §382.0173, and §382.054; and FCAA, 42 USC, §§7401 et seq .

§122.420.General Clean Air Interstate Rule Annual Trading Program Permit Requirements.

(a) For each Clean Air Interstate Rule (CAIR) nitrogen oxides (NO x ) source and CAIR sulfur dioxide (SO2 ) source required to have a federal operating permit, such permit must include a CAIR permit. The CAIR portion of the federal permit must be administered in accordance with this chapter as applicable, except as provided otherwise by 40 Code of Federal Regulations (CFR) Part 96, Subpart CC and Subpart CCC.

(b) Each CAIR permit must contain, with regard to the CAIR NO x source and CAIR SO 2 source and the CAIR NO x units and CAIR SO 2 units at the source covered by the CAIR permit, all applicable CAIR NO x Annual Trading Program, and CAIR SO 2 Trading Program requirements and must be a complete and separable portion of the federal operating permit or other federally enforceable permit under subsection (c) of this section.

(c) For each CAIR NO x opt-in unit and CAIR SO 2 opt-in unit that is required to have a federally enforceable permit, such permit must include a CAIR permit. The CAIR portion of the federally enforceable permit must be administered in accordance with the commission's regulations for such permit as applicable, except as otherwise provided under 40 CFR Part 96, Subparts II and III.

(d) No CAIR permit may be issued, amended, reopened, or renewed until the United States Environmental Protection Agency has received a complete certificate of representation under 40 CFR §96.113 or §96.213 for a CAIR designated representative of the CAIR NO x and CAIR SO 2 source and the CAIR NO x and CAIR SO 2 units at the source.

§122.422.Submission of Clean Air Interstate Rule Permit Applications.

(a) The Clean Air Interstate Rule (CAIR) designated representative of any CAIR nitrogen oxides (NO x ) source and CAIR sulfur dioxide (SO 2 ) source required to have a federal operating permit shall submit to the executive director a complete CAIR permit application under §122.424 of this title (relating to Information Requirements for Clean Air Interstate Rule Permit Applications) for the source covering each CAIR NO x unit and CAIR SO2 unit at the source by June 1, 2007, or at least 18 months prior to the date that the CAIR NO x unit and CAIR SO 2 unit commences operation.

(b) For a CAIR NO x source and CAIR SO 2 source required to have a federal operating permit, the CAIR designated representative shall submit a complete CAIR permit application to the executive director under §122.424 of this title for the source covering each CAIR NO x unit and CAIR SO 2 unit at the source to renew the CAIR permit in accordance with this chapter.

§122.424.Information Requirements for Clean Air Interstate Rule Permit Applications.

A complete Clean Air Interstate Rule (CAIR) permit application must include the following elements concerning the CAIR nitrogen oxides (NOx ) source and CAIR sulfur dioxide (SO 2 ) source for which the application is submitted, in a format prescribed by the executive director:

(1) identification of the CAIR NO x source and CAIR SO 2 source;

(2) identification of each CAIR NO x unit and CAIR SO 2 unit at the CAIR NO x source and CAIR SO 2 source;

(3) the standard requirements under 40 Code of Federal Regulations §96.106 and §96.206;

(4) a copy of the complete certificate of representation submitted to the United States Environmental Protection Agency as required under §122.420(d) of this title (relating to General Clean Air Interstate Rule Annual Trading Program Permit Requirements); and

(5) any other information requested by the executive director.

§122.426.Clean Air Interstate Rule Permit Contents and Term.

(a) Each Clean Air Interstate Rule (CAIR) permit must contain, in a format prescribed by the executive director, all elements required for a complete CAIR permit application under §122.424 of this title (relating to Information Requirements for Clean Air Interstate Rule Permit Applications).

(b) Each CAIR permit must incorporate the definitions of terms under 40 Code of Federal Regulations §96.102 and §96.202 and, upon recordation by the United States Environmental Protection Agency administrator under 40 Code of Federal Regulations Part 96, Subparts FF, GG, II, FFF, GGG, and III every allocation, transfer, and deduction of a CAIR nitrogen oxides (NO x ) allowance and CAIR sulfur dioxide (SO2 ) allowance to or from the compliance account of the CAIR NO x source and CAIR SO 2 source covered by the permit.

(c) The executive director shall set the term of the CAIR permit as necessary to facilitate coordination of the renewal of the CAIR permit with issuance, revision, reopening, or renewal of the CAIR NO x source's and CAIR SO 2 source's federal operating permit.

§122.428.Clean Air Interstate Rule Permit Revisions.

Except as provided in §122.426(b) of this title (relating to Clean Air Interstate Rule Permit Contents and Term), the executive director shall revise the Clean Air Interstate Rule permit, as necessary, in accordance with this chapter or the regulations for other federally enforceable permits regarding permit revisions as applicable addressing permit revisions.

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 July 14, 2006.

TRD-200603758

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-6087

3. CLEAN AIR MERCURY RULE

30 TAC §§122.440, 122.442, 122.444, 122.446, 122.448

STATUTORY AUTHORITY

The new sections are adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The new sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; HB 2481, §2 of the 79th Legislature, codified at §382.0173, concerning adoption of rules regarding certain SIP requirements and standards of performance for certain sources; and §382.054, concerning federal operating permits; and FCAA, 42 USC, §§7401 et seq ., which require states to include in their SIPs adequate provisions prohibiting any source within the state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance of, the NAAQS in any other state.

The adopted new sections implement THSC, §§382.002, 382.011, 382.012, HB 2481, §2 of the 79th Legislature, codified at §382.0173, and §382.054; and FCAA, 42 USC, §§7401 et seq .

§122.444.Information Requirements for Mercury Budget Permit Applications.

A complete mercury budget permit application must include the following elements concerning the mercury budget source for which the application is submitted, in a format prescribed by the executive director:

(1) identification of the mercury budget source;

(2) identification of each mercury budget unit at the mercury budget source;

(3) the standard requirements under 40 CFR §60.4106;

(4) a copy of the complete certificate of representation submitted to United States Environmental Protection Agency as required under §122.440(c) of this title (relating to General Mercury Budget Trading Program Permit Requirements); and

(5) any other information requested by the executive director.

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 July 14, 2006.

TRD-200603759

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 17, 2006

For further information, please call: (512) 239-6087

Chapter 285. ON-SITE SEWAGE FACILITIES

The Texas Commission on Environmental Quality (commission) adopts amendments to §§285.2, 285.7, 285.33, 285.50, 285.61, 285.70, 285.71, and 285.90. The commission also adopts the repeal of §285.64 and new §285.64 and §285.65. The amendments to §§285.7, 285.33, and 285.61 and new §285.64 and §285.65 are adopted with changes to the proposed text as published in the February 24, 2006, issue of the Texas Register (31 TexReg 1173). The amendments to §§285.2, 285.50, 285.70, 285.71, and 285.90 and the repeal of §285.64 are adopted without changes and will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

The adopted rules implement requirements in House Bill (HB) 2510, 79th Legislature, 2005, relating to the regulation of on-site sewage disposal systems using aerobic treatment and the maintenance of those systems. The adopted rules also address enforcement for noncompliance. HB 2510 impacts two chapters within 30 TAC. These are Chapter 30, Occupational Licenses and Registrations, and Chapter 285, On-Site Sewage Facilities. This adoption addresses the revisions to Chapter 285. The changes to Chapter 30 have previously been addressed and adopted in a separate rulemaking (Rule Project Number 2005-039-030-CE).

This adopted rulemaking addresses the registration requirements for maintenance companies that provide service or maintenance of on-site sewage disposal systems using aerobic treatment. It also addresses requirements for a homeowner who wishes to maintain the aerobic system at the homeowner's residence without the necessity of a maintenance contract with a maintenance company. Additionally, there are three changes to Chapter 285 not related to HB 2510. The first relates to revising the definition of subdivision, and the other two changes relate to more specific direction for design of mound and soil substitution disposal options.

The commission administers the On-Site Sewage Facility (OSSF) Program that currently includes executive director delegation of OSSF authority to counties, municipalities, and river authorities.

The adopted rules create requirements for maintenance companies, individuals who provide maintenance for compensation, and homeowners who perform their own maintenance. The adopted rules also clarify the definitions of maintenance company (to include the Chapter 30 definition of maintenance provider) and subdivision (to agree with the definition of subdivision within the Local Government Code). Finally, the adopted rules also clarify OSSF disposal options of mound drainfields and soil substitution drainfield design options.

The adopted rules further define the commission's regulations regarding servicing or maintenance of OSSFs using aerobic treatment under Texas Health and Safety Code (THSC), Chapter 366. The purpose of the statute is to regulate maintenance companies and their ability to service and maintain on-site sewage disposal systems using aerobic treatment. The failure of an OSSF is the fundamental cause of OSSF-related public health hazards and provides a medium for the transmission of disease. The failure of an OSSF may be caused by a number of factors, including inadequate soil texture, improper construction, improper planning, improper installation, and inadequate maintenance. Approximately 25% of all homes in Texas use OSSFs because options for centralized collection, treatment, and disposal systems are not available. In Fiscal Year 2004 alone, there were more than 41,000 newly permitted OSSFs in Texas. Of these, nearly 23,000 (53%) were aerobic systems.

The adopted rules specify requirements for maintenance companies to obtain an occupational registration to perform service and maintenance of on-site sewage disposal systems using aerobic treatment. The significant revisions in these rules include changes to the requirements for maintenance companies, installers, enforcement proceedings, and training for maintenance companies.

Finally, the adopted rules delineate the training requirements for homeowners, installers, and maintenance companies. Specifically, these rules require six hours of training for homeowners who perform their own maintenance and a minimum of 16 hours of training for registered maintenance companies.

SECTION BY SECTION DISCUSSION

The commission adopts administrative changes throughout these sections to be consistent with Texas Register requirements and other agency rules and guidelines and to conform to the drafting standards in the Texas Legislative Council Drafting Manual , November 2004.

Subchapter A - General Provisions

The adopted amendment to §285.2, Definitions, provides for consistency with the definition of Edwards Aquifer Recharge Zone, as provided in 30 TAC Chapter 213, Edwards Aquifer. The adopted amendment to §285.2 also provides additional scope to the definition for maintenance company to include maintenance providers, as defined in §30.7, Definitions, and to include the new provisions from HB 2510 relating to maintenance provided for compensation. Additionally, the adopted amendment to §285.2 would provide an updated definition of subdivision to reflect the subdivision definition found in Local Government Code, §232.001(a-1).

The adopted amendment to §285.7, Maintenance Requirements, provides current rules for maintenance companies, which reflects changes to THSC, §366.0515(n), relating to certification, training, and registration for both maintenance companies and individuals employed by maintenance companies. The statute also eliminates the current acceptance of a wastewater Class D license as a prerequisite for performing maintenance. However, provisions have been added for wastewater Class D licensees to continue to provide maintenance until September 1, 2008, provided that they held a valid wastewater Class D license as of August 31, 2006. Finally, the current rules allow homeowner maintenance in counties with a population less than 40,000. The adopted amendment reflects the provisions of THSC, §366.051(g) - (k), and allows homeowners in every county to perform their own aerobic system maintenance if the homeowner has six hours of commission-approved training from either the manufacturer or installer, under specified time frames, and the county has not imposed more stringent standards. The adopted amendment also provides for routine inspections by the permitting authority, not to be greater than once every five years unless the owner has failed to properly maintain the aerobic system and requires a homeowner to obtain a maintenance contract if the aerobic system is not properly maintained.

Subchapter D - Planning, Construction, and Installation Standards for OSSFs

The adopted amendment to §285.33, Criteria for Effluent Disposal System, provides the construction requirements for a mound drainfield in subsection (d)(3) and quantifies the positive allowances for slopes and the existing or new soil interface. The adopted amendment to §285.33 also provides clearer requirements for designing a soil substitution drainfield in subsection (d)(4) and does not allow for soil substitution using Class III soils, which generally tend to erratically treat and disperse effluent.

Subchapter F - Licensing and Registration Requirements for Installers, Apprentices, Designated Representatives, Site Evaluators, and Maintenance Companies

The adopted amendment to §285.50, General Requirements, provides for commission registration of maintenance companies.

The adopted amendment to §285.61, Duties and Responsibilities of Installers, provides for mandatory homeowner training by the installer of an aerobic system when requested by the homeowner.

The adopted repeal of §285.64, Suspension or Revocation of License or Registration, is replaced by new adopted §285.64, Duties and Responsibilities of Maintenance Companies. This section addresses the requirements in §285.7 for maintenance companies and assists in enforcement referrals by permitting authorities and the commission.

The adopted new §285.65, Suspension or Revocation of License or Registration, includes all of the provisions currently found in §285.64 and adds the revocation of a maintenance company's registration for failure to either properly maintain an aerobic system or submit required reports. This section reflects the provisions of §285.7 for maintenance companies and will assist in enforcement referrals.

Subchapter G - OSSF Enforcement

The adopted amendment to §285.70, Duties of Owners With Malfunctioning OSSFs, includes specific language for homeowners who desire to maintain their own aerobic systems, as reflected in §285.7(c)(4).

The adopted amendment to §285.71, Authorized Agent Enforcement of OSSFs, adds provisions in the rules for complaints regarding the performance of the maintenance of an aerobic system by maintenance companies or homeowners.

Subchapter I - Appendices

The adopted amendment to §285.90, Figures, revises references in Figure 2, the model deed and affidavit, from the Texas Natural Resource Conservation Commission (TNRCC) to the Texas Commission on Environmental Quality (TCEQ). Additionally, the adopted amendment to §285.90 adds instructions in Figure 3, the sample testing and reporting record for homeowners providing their own maintenance. This also reflects the provisions within §285.7(d), Maintenance Requirements. The adopted amendment to §285.90 also deletes Class III soils as fill in Figure 4, soil substitution drainfields for the typical drainfields - sectional view diagram. This reflects the design changes in §285.33(d)(4), Criteria For Effluent Disposal Systems, relating to soil substitution drainfields.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed this rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and 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. The intent of this adoption is to implement legislation that allows regulation of on-site sewage disposal systems using aerobic treatment and the maintenance of those systems. The adopted rules also address enforcement for noncompliance. The adopted rules are intended to establish procedures for regulation and do not adversely affect, in a material way, the economy, a section of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state.

In addition, the adopted rules are not subject to Texas Government Code, §2001.0225, because they do not meet the four criteria specified in §2001.0225(a). Section 2001.0225(a) applies to a rule adopted by a commission, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and a commission or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the commission instead of under a specific state law. The adopted rules do not meet any of these requirements. First, these revisions do not exceed a standard set by federal law as there are no federal requirements for maintaining OSSFs. Second, these revisions do not exceed an express requirement of state law but are being adopted to implement state law. Therefore, the rulemaking does not exceed an express requirement of state law. Third, the commission is not a party to a delegation agreement with the federal government concerning a state and federal program that would be applicable to requirements set forth in these rules. Therefore, there are no delegation agreement requirements that could be exceeded by these rules. Fourth, this adopted rulemaking does not adopt a rule solely under the general powers of the commission. The requirements that would be implemented through these rules are specified in THSC, Chapter 366, which requires the commission to enact rules governing the installation of OSSFs. Therefore, the commission does not adopt these rules solely under the commission's general powers.

Thus, a regulatory analysis is not required because the adopted rules do not meet the criteria of a major environmental rule contained in Texas Government Code, §2001.0225. The commission invited public comment but no comments were received on the draft regulatory impact analysis determination.

TAKINGS IMPACT ASSESSMENT

The commission performed a preliminary assessment of these rules in accordance with Texas Government Code, §2007.043. The following is a summary of that assessment. The specific purpose of the rules is to regulate activities having the potential for causing pollution of the waters in Texas. The rules will substantially advance this specific purpose by the regulation of on-site sewage disposal systems using aerobic treatment as well as maintenance and enforcement of those systems. Promulgation and enforcement of the adopted rules would be neither a statutory nor a constitutional taking because they do not adversely affect private real property. The rulemaking does 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 a governmental action. Texas Government Code, Chapter 2007, does not apply to this rulemaking because the promulgation and enforcement of these rules will not create a burden on private real property.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission reviewed the adopted rulemaking and found that the adoption is subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act, Texas Natural Resources Code, §§33.201 et seq ., and therefore must be consistent with all applicable CMP goals and policies. The commission conducted a consistency determination for the adopted rules in accordance with Coastal Coordination Act Implementation Rules, 31 TAC §505.22, and found the adopted rulemaking is consistent with the applicable CMP goals and policies.

CMP goals applicable to the adopted rule(s) include: to protect, preserve, restore, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas; to ensure sound management of all coastal resources by allowing for compatible economic development and multiple human uses of the coastal zone; and to ensure and enhance planned public access to and enjoyment of the coastal zone in a manner that is compatible with private property rights and other uses of the coastal zone.

CMP policies applicable to the adopted rule(s) include that commission rules under THSC, Chapter 366, governing on-site sewage disposal systems require that on-site disposal systems be located, designed, operated, inspected, and maintained so as to prevent releases of pollutants that may adversely affect coastal waters.

The adopted rules are consistent with the goals and policies because they require testing, sampling, and maintenance of aerobic systems sufficient to prevent releases of pollutants.

Promulgation and enforcement of these rules will not violate or exceed any standards identified in the applicable CMP goals and policies because the adopted rules are consistent with these CMP goals and policies and because these rules do not create or have a direct or significant adverse effect on any coastal natural resource areas.

PUBLIC COMMENT

There was no public hearing held on this rulemaking.

RESPONSE TO COMMENTS

The commission received 29 written comments concerning the proposed rules. Comments were received from State Representative Dennis Bonnen and Dianne Helms of State Senator Craig Estes's Office, AAA Wastewater Installation & Maintenance Company, A.C.E. Wastewater Disposal System, Brazos Wastewater Systems LLC, Bell County Public Health District, Clearstream Wastewater Systems, Inc., Coleman Aerobic Septic, Environmental Construction Services, Fayette County, Harris County Public Infrastructure Department, Meiners Construction Company, Myrtle Springs Septic Systems, Snowden Onsite Septic, Inc., South Texas Wastewater Treatment, Texas On-Site Wastewater Association, Travis County Transportation and Natural Resources, Whitt Septic Systems, and ten individuals. The commenters were opposed to a variety of portions within the rulemaking, whether related to this rule adoption or not.

One individual commented concerning HB 2510 in anticipation of the proposed rules which was received September 9, 2005, and Coleman Aerobic Septic System Inspection/Maintenance submitted comments on October 31, 2005. However, both sets of comments were received well in advance of the final version and release of the proposed rules to the public, which occurred in January 2006. As a result, these comments were excluded from response.

Finally, A.C.E. Wastewater Disposal System commented on the rules during the comment period and provided the commission with a similar letter addressed to TOWA. The letter addressed to TOWA was not included in the responses. However, the letter addressed to the commission was responded to in the preamble.

General

One individual commented that the commission has allowed the septic industry to: charge high fees for aerobic system maintenance, not always require permits, not address systems in need of repair in a timely manner, and not require inspections. This individual also recommended an inspection program for all home sites with septic systems which would establish: acquisition of a timely permit, proof of a correctly functioning system, periodic inspections, and a local contact for homeowners to report overflowing systems. Another individual commented that there would be an increase in pollution due to homeowner inability to properly maintain an aerobic system.

These comments are beyond the scope of this rulemaking. However, the Chapter 285 rules address each of these comments and the commission's Web site also lists its authorized agents, their location, and contact information. No changes were made in response to this comment.

Clearstream Wastewater Systems, Inc. (Clearstream) commented that their installed systems may suffer from improper maintenance under the proposed rules and the proposed rules are excessive and impossible to comply with and contravene the specific language of HB 2510.

The commission agrees that any aerobic system may malfunction with improper maintenance. Clearstream's specific comments and the commission's responses follow in the next section, relating to specific comments. No changes were made in response to this comment.

Clearstream commented that the commission ". . . has chosen the limited statutory grant of authority in HB 2510 as a license to create an entirely new regulatory program . . . Rather than just satisfy the demands of the statute, the rule proposal takes the statute as a starting point and then creates a major new regulatory program out of whole cloth -- placing responsibilities and penalties upon wastewater system manufacturer's { sic } that are both in excess of what the statute requires and at times, in contravention with what the statute allows."

The commission responds that statutory authority to create a registration program was specific in Texas Health and Safety Code (THSC), §266.0515(n). Additionally, the statute specifies in §366.0515(h) that the responsibility for homeowner training go to either the manufacturer or installer. While the commission has proposed amendments to existing rules for installers with respect to homeowner training, there are no provisions for manufacturers who choose to decline to provide homeowner training for aerobic systems. However, the commission is not required to approve a manufacturer's product when the manufacturer has not satisfied conditions for review. For example, 30 TAC §285.32(c)(5) requires a review of a manufacturer's state-listed product every seven years. Manufacturers who fail to comply can have their product(s) removed (§285.32(c)(5)(D)). The commission views a manufacturer's failure to train a homeowner (when requested) as a failure to comply with the rules and the only available alternative is delisting the product(s). No changes were made in response to this comment.

Clearstream commented that while THSC, §366.0515(o), prohibits the commission from dictating to manufacturers who are to be certified as a maintenance provider, this prohibition implicitly extends to homeowner training as well.

While the commission agrees that the statute prohibits the commission from dictating to manufacturers who are to be certified, the commission disagrees that this extends equally to homeowners as it was neither stated nor included in §366.0515(h) and §366.0515(o). No changes were made in response to this comment.

Meiners Construction Company (Meiners) commented that counties should have the option of allowing homeowner maintenance.

Counties have the option of allowing or not allowing homeowner training. THSC, §366.032(b), allows authorized agents to adopt more stringent requirements when they provide greater public health and safety protection. Additionally, there are several authorized agents who have received approval to require maintenance contracts for all aerobic systems. No changes were made in response to this comment.

AAA Wastewater Installation & Maintenance Company (AAA) commented that the TCEQ is not doing its job in regulating local permitting authorities and that half of the local permitting authorities neither have the tools nor ability to accurately inspect installation work. Additionally, the TCEQ should be fining these authorized agents for not enforcing the rules.

While the comments are not part of the rulemaking, there are provisions in Subchapter B of Chapter 285 concerning delegation to local authorities and revocation of this delegation. Revocation of an order and charge-back fees could be part of an enforcement action against an authorized agent who fails to properly carry out its duty related to OSSF. No changes were made in response to this comment.

Dianne Helms of State Senator Craig Estes's office commented that the fiscal note, under PUBLIC BENEFITS AND COSTS, stated that installers and manufacturers would be tracking and reporting to permitting authorities which homeowners have been trained to perform their own aerobic system maintenance.

The commission's proposed rules require manufacturers and installers who train homeowners to provide only a written certificate or letter to the local permitting authority, as found in §285.7(d)(4)(A)(ii). No changes were made in response to this comment.

Ms. Helms also commented that the limitation to provide aerobic system maintenance to counties of 40,000 persons was in the commission's proposed rules.

The commission could not find where the limitation was still in effect in the proposed rules. No changes were made in response to this comment.

The Harris County Public Infrastructure Department (Harris County) commented that the TCEQ's estimate of $100,000 costs to state and local governments does not include costs to the TCEQ's regional offices and that Harris County's costs would be closer to $185,000. Harris County recommended that the definition of "Maintenance" is currently overly broad, exceeds the legislative intent in the statute, and should be revised per their recommendation.

The fiscal note did not include data from Harris County regarding enforcement and additional staff costs. However, the fiscal note does say that costs would depend upon how many aerobic facilities are in the jurisdiction of the local permitting authority and the necessity for personnel and equipment upgrades as well as their ability to provide enforcement. The estimated upward cost of $100,000 may have been low for Harris County, but was based upon the best information program staff had at that time. No changes were made in response to this comment.

Environmental Construction Services (Environmental) commented that Mr. Horvath's estimate for the cost per employee was not reasonable and that $500 for the basic training cost per employee should be considered in addition to employee registration.

In the section titled SMALL AND MICRO-BUSINESS ASSESSMENT, the training class was estimated to cost between $200 and $400 at the time the fiscal note was written. Costs for training from each manufacturer was unknown at the time. The assessment incorrectly assumed a $70 per year cost for registration. Therefore, the assessment should have read "training and registration costs are estimated to be between $270 and $470" per employee performing aerobic system maintenance.

TOWA commented that there were no provisions in the proposed rules relating to continuing education requirements for maintenance providers and suggested that the commission consider doing so with an emphasis on advance maintenance provider training.

These comments are beyond the scope of this rulemaking but could be addressed in any future rulemaking for 30 TAC Chapter 30.

TOWA commented that the commission's current policy for course approval for the basic maintenance provider course is insufficient because other continuing education providers may not be sufficiently familiar with the provisions of HB 2510. TOWA encouraged the commission to ". . . follow the national standards in selecting only those with University affiliations or State/National Associations who develop training materials and provide education programs to the onsite wastewater industry."

These comments are beyond the scope of this rulemaking. No changes were made in response to this comment.

Travis County Transportation and Natural Resources Onsite Wastewater Program (Travis County) recommended revisions to other portions of the rules, such as: requiring the five-foot setback for all disposal systems (including surface application and drip irrigation), revising the requirement that any system which needs component replacement (such as replacement of a broken pipe or pump tank) not be required to meet current standards when the system does not have a history of operational problems or failure, addition of soil/material specifications for bedding pipe, adding a requirement that all non-residential OSSFs have a grease interceptor as well as a method for sizing them, such as in the Florida standards, and Table III be amended to include wastewater usage rates for businesses such as barber and beauty shops, dentist and doctor offices, churches, funeral homes, fitness gyms, self storage warehouses, carry-out food outlets, and convenience stores with fast food restaurant attachments.

These comments are beyond the scope of this rulemaking but can be addressed in future revisions to Chapter 285. No changes were made in response to this comment.

Two individuals commented that the new $70 maintenance provider registration fee was not equitable to those currently providing maintenance.

Registration fees are specified in 30 TAC Chapter 30 and are not within the scope of the Chapter 285 rules. No changes were made in response to this comment.

The Bell County Public Health District (Bell County) commented that the cost associated with homeowner training will not be reasonable for the homeowner. Meiners asked who will be paying the cost associated with training homeowners. Additionally, Bell County asked 17 questions concerning implementation of the rules. These questions were addressed in the commission's written response to Bell County, dated April 24, 2006.

The commission agrees with Bell County that the cost for homeowner training may be perceived as unreasonable but neither the statute nor the rules limit the trainer's fees and assumes that the trainer will charge the homeowner for the training. No changes were made in response to this comment.

Meiners commented that the cost of installing an aerobic system will increase.

The commission agrees that this is a possibility. No changes were made in response to this comment.

Fayette County commented that there were currently no courses available for training maintenance providers and therefore no one can comply with the proposed rules. Fayette County also commented that designated representatives (DRs) should be given the authority to issue spot citations for OSSF violations, DRs should be trained and certified to take OSSF effluent samples, conditionally legalize outhouses, eliminate the ten-acre rule, provide state-mandated pay equity for all DRs, and to rewrite the graywater rules because they are confusing. Finally, Fayette County asked 19 questions concerning implementation of the rules.

At the time of Fayette County's letter, while there were no approved maintenance training courses, the commission had received a proposal for a maintenance provider training course which is under review. Fayette County's recommendations are beyond the scope of this rulemaking but can be considered in a future rulemaking. Finally, the commission responded to Fayette County's 19 questions concerning implementation of the rules in a letter, dated April 24, 2006. No changes were made in response to this comment.

Harris County commented that the requirement for the permitting authority to have a valid maintenance contract, as a condition to construct, should be changed to be as a condition to operate. Harris County cites doing so gives the homeowner an opportunity to solicit bids from different aerobic system manufacturers.

This statement is beyond the scope of this rulemaking. No changes to the rules were made in response to this comment.

South Texas Wastewater Treatment requested rule changes for the minimum dosing volume for spray systems, smaller minimum pump tank size, new requirements for an equalization basin to regulate effluent flow, and additional flexibility for a qualified designer in designing an on-site sewage facility.

These comments are beyond the scope of this rulemaking which is only to address the provisions of HB 2510, definitions for maintenance and subdivision, mound disposal, and soil substitution design. These comments may be addressed in a future revision of Chapter 285. No changes were made in response to this comment.

Specific

State Representative Dennis Bonnen commented that the commission redefine "Maintenance" to exclude replacement of major parts and alterations of the system. He also commented that the legislation was intended to leave major repairs to licensed professionals. Additionally, Harris County, Snowden Onsite Septic, Inc. (Snowden), and TOWA offered modifications to the existing definition for maintenance relating to the delineation of responsibility of homeowners performing their own aerobic system maintenance versus certified maintenance personnel. Harris County also recommended a new definition for "Maintenance findings."

The revised maintenance definitions recommended by the commenters propose to limit the scope of homeowners' ability to maintain their aerobic treatment unit. The 30 TAC Chapter 285 rules do not allow any change to a permitted system without the permitting authority's prior review and approval. In reviewing the proposed revised definitions and current practices in counties with a population less than 40,000, the commission envisions empowering homeowners in counties above 40,000 population with the option for all aspects of aerobic system maintenance as the smaller counties. The definition for "Alter" also requires prior review and approval from the permitting authority. Finally, Chapter 30 allows homeowner maintenance which specifically includes repairs to their own aerobic systems. No changes were made in response to this comment.

Two individuals questioned the need to license professionals who have been providing maintenance services in the past.

The statute requires all maintenance providers to be registered with the commission. No changes were made in response to this comment.

One individual asked why was maintenance limited to only those certified by the manufacturer of the commenter's aerobic system.

Section 285.7(b)(1)(A) of the proposed rules requires that maintenance be provided by an individual certified by the manufacturer of the OSSF. This is consistent with current rules in §285.7(b)(1)(A). No changes were made in response to this comment.

One individual asked why six hours of training were required for a procedure that doesn't take 45 minutes to complete.

HB 2510 specifically states that up to six hours training for homeowner maintenance is required. In this requirement, the commission is charged with developing training which includes instruction regarding public health and safety of proper maintenance of the system and a demonstration of the procedure for performing a scheduled maintenance. No changes were made in response to this comment.

Travis County commented that there is no justification for a maintenance provider to have an Installer II license and that current maintenance providers without an Installer II license may find existing maintenance contracts to be at risk for fulfilling maintenance obligations.

The commission understands Travis County's point but disagrees because the requirement was included in HB 2510 and those individuals performing maintenance without an Installer II license may continue to perform maintenance as long as they: 1) are employed in a company which employs an Installer II; 2) satisfactorily complete a 16-hour, commission-approved basic maintenance course; 3) have a business relationship with the manufacturer; and 4) complete any other reasonable requirements established by the manufacturer. Finally, the maintenance person must be certified by the manufacturer and registered with the commission. No changes were made in response to this comment.

AAA, A.C.E. Wastewater Disposal System (A.C.E.), Environmental, Meiners, Travis County, and one individual commented that there was a significant disparity between the amount of time required for a professional maintenance provider and homeowners. The disparity is between the requirement for up to six hours' training required for homeowners and a minimum of 16 hours' training for professionals. Environmental and Meiners also recommended that homeowners take the same course as maintenance providers to alleviate this disparity. Travis County recommended 12 hours' training for homeowners. Additionally, Whitt Septic Services (Whitt) commented that a 16- hour course in basic maintenance ". . . is a joke . . ." for those already performing maintenance and Meiners commented that six hours would not be a sufficient amount of time, resulting in more homeowner-maintained aerobic systems which would fail, resulting in more enforcement action for permitting authorities.

These requirements are from the statute which specify training times. No changes were made in response to this comment.

TOWA commented that 16 hours of intensive training is insufficient time for training maintenance providers but agrees with the commission's limitation of this training to classroom training.

The commission acknowledges TOWA's comment concerning the classroom-only training. The commission responds that the basic course is intended to provide only basic information for maintenance providers, not manufacturer-specific training. No changes were made in response to this comment.

TOWA commented that they support the commission's position that the commission will not require re-certification for maintenance providers who are currently certified by a manufacturer.

The commission acknowledges TOWA's support. The commission reiterates that although a maintenance provider has a manufacturer's certification, successful completion of the basic maintenance course is still required for registration. No changes were made in response to this comment.

Two individuals commented that they are currently Installer II licensees who provide maintenance and should not be required to take a class in which they are already trained. Another individual requested an exemption for any installer who currently performs maintenance on aerobic systems.

The statute created a registration for all maintenance providers and in doing so, requires the commission to develop course work for certification by the manufacturer and registration with the commission. No changes were made in response to this comment.

Snowden commented that the statute requires an Installer II license and did not give leeway for Wastewater D licensees.

The commission proposed a two-year phaseout of the Wastewater D licensee as an option in order for all Wastewater D licensees to obtain Installer II certification or affiliate with a maintenance company that employs an Installer II. Immediate disallowance of the Wastewater D option could also jeopardize thousands of existing maintenance contracts performed by Wastewater D licensees. No changes were made in response to this comment.

One individual requested that maintenance providers with a Wastewater D license be permitted to maintain systems in perpetuity as long as all other provisions for maintenance registration are met. This individual commented that if a homeowner can be trained in six hours that the maintenance provider could be trained in the same amount of time as well.

HB 2510 states that an Installer II license must be held by at least one person in the company. Additionally, the commission proposed a two-year phaseout of the Wastewater D licensee as an option in order for all Wastewater D licensees to obtain Installer II certification or affiliate with a maintenance company that employs an Installer II. The statute also makes a distinction between homeowners and those who provide maintenance for compensation. Homeowner training is not the same for those who provide maintenance service and receive compensation. No changes were made in response to this comment.

Harris County recommended that someone other than the designer of a nonstandard system be given the flexibility to train a homeowner, in the case when the designer cannot train the homeowner.

The commission does not agree that someone other than the designer of a nonstandard system be given the flexibility to train a homeowner because doing so allows someone not intimately involved in or possibly aware of particular design details to assume responsibility of its operational training of the homeowner. However, in the case when the original designer is unavailable to train the homeowner, the commission has no objection to a local permitting authority accepting an alternate trainer, as proposed by Harris County. This could be addressed in a future revision to the Chapter 285 rules. No changes to the rules were made in response to this comment.

One individual asked what happens when the house is sold and who will be contacted to train the new homeowner(s). Finally, this individual asked if this information will be included in the sales contract.

The proposed rules provide that after a house sale, the new homeowner must obtain training from either the installer or manufacturer, as stated in §285.7(c)(3)(C). Finally, the commission neither has jurisdiction over a real estate sales contract provision nor can require this information to be part of a real estate sales contract. No changes were made in response to this comment.

One individual commented that the rules should not require homeowners who currently perform their own aerobic system maintenance from being retrained in aerobic system maintenance.

The commission agrees with this comment. Homeowners who currently perform their own aerobic system maintenance are not required to be retrained. No changes were made in response to this comment.

AAA, A.C.E., Clearstream, Meiners, Whitt, and two individuals commented that homeowners are not qualified to provide maintenance or will not provide adequate maintenance of their systems.

This requirement is the crux of this rulemaking package which allows homeowners to provide their own aerobic system maintenance. No changes were made in response to this comment.

A.C.E., Brazos, Meiners, and one individual commented that there would be a degradation in ground and surface water quality by homeowners who maintain their own systems.

The statute allows homeowners to provide their own aerobic system maintenance with training. No changes were made in response to this comment.

Harris County commented that maintenance contracts should be amended to allow electronic maintenance monitoring software as confirmation that the maintenance contract was renewed.

This comment is beyond the scope of this rulemaking. No changes to the rules were made in response to this comment.

Environmental commented that manufacturers and installers will incur liability when training a homeowner to maintain an aerobic treatment system. Environmental also provided a statement from their insurance company stating that they would not be protected under their general liability policy.

The commission cannot control if someone decides to pursue litigation. Any company or individual can be sued at any time by any party without regard to legal accuracy or sufficiency. The rules require the manufacturer or installer to train a homeowner when requested by the homeowner. No changes were made in response to this comment.

One individual agreed with the requirement that either the manufacturer or the installer train the homeowner.

The commission acknowledges this comment. No changes were made in response to this comment.

Environmental commented that there is a disparity between the need for a certification of those who train maintenance providers while there is no certification requirement for those who train homeowners.

The commission agrees that there appears to be a disparity for training maintenance providers and homeowners. However, HB 2510 specifically states that the basic maintenance provider course be approved by the commission but did not state the same for homeowner training. As a result, the commission does not require review/approval of the homeowner training and requires review/approval of the basic maintenance provider course. Additionally, for the basic maintenance course, instructors are not certified by the commission but must meet certain qualifications, per commission Regulatory Guidance Number 373. No changes were made in response to this comment.

Clearstream, Harris County, and one individual commented that the commission's proposed rules go beyond the statutory requirement for training homeowners within the initial two-year period by requiring training when requested by the homeowner.

The commission disagrees with this comment. Limiting the rules to only new systems and those currently within the initial two-year period potentially deprives over 100,000 homeowners with aerobic systems the opportunity to perform their own maintenance. Additionally, the wording in the statute to which Clearstream and Harris County refer is followed by the words "if applicable." The commission interprets this portion of the statute to mean that homeowner training can be obtained at any time, including the initial two-year period in anticipation of the homeowner maintaining the system after the initial maintenance term has expired. No changes were made in response to this comment.

Meiners and one individual commented that third-party training for homeowners would be preferential to requiring installers and manufacturers.

The commission agrees in principle and such training would promote consistency in training for homeowners. However, training on an owner's aerobic treatment unit would necessitate the third party's approval to do so by each manufacturer, along with manufacturer-specific unit details. No changes were made in response to this comment.

One individual asked to be responsible for the required reporting to the local permitting authority and if homeowner training could be sufficient by attending an installer's training class.

An installer's training class (21 hours) is longer than the proposed six hours of homeowner training and does not sufficiently cover maintenance and reporting requirements for specific aerobic treatment units. No changes were made in response to this comment.

Clearstream commented that the commission had no authority to delist a manufacturer who refused a homeowner training when requested.

While the commission understands Clearstream's arguments, the proposed rules do not prevent any manufacturer from outsourcing training, either through its agents, installers, or training in large groups. Manufacturers must be held accountable for violating the rules in regard to homeowner training. Since the commission approves the product because it meets TCEQ requirements, the commission may also not approve the product when statute violations occur. No changes were made in response to this comment.

State Representative Dennis Bonnen commented that a 30-day training period will be burdensome to firms that have a large number of clients spread over a large area. Clearstream commented that they could not accommodate training 5,000 homeowners per month in training at their residences. Additionally, Harris County, TOWA, and one individual commented that the 30-day time frame to train a homeowner is inadequate due to logistics relating to scheduling, locations, facilities, and manpower for training. Commenters cited that this may be especially pertinent in the initial period after the rule adoption. TOWA recommended training four times per year for homeowners while Clearstream and Harris County cited the training only be offered during the initial two-year period after installation.

The statute, in §366.0515(h) states that a homeowner who purchases a residence with an aerobic treatment system has 30 days after taking possession to obtain maintenance training or else the homeowner must obtain a maintenance contract. The commission applied this same time frame to existing homeowners who wish to maintain their own aerobic system. As a result, extending the 30-day period would not be consistent with the statute. No changes were made in response to these comments.

TOWA commented that homeowner training responsibility should rest solely with the manufacturer in classes held on a quarterly basis. TOWA also commented that only the manufacturer be required to provide the permitting authority and homeowner with a written certificate or letter stating that the owner received and completed the required training.

TOWA's recommendation is well taken but HB 2510 requires either the manufacturer or installer train the homeowner. No additional changes were made in response to this comment.

Clearstream, Environmental, Harris County, and Snowden commented that installers should not be required to train homeowners in aerobic system maintenance. Additionally, A.C.E., Environmental, Meiners, Snowden, TOWA, and Whitt commented that installers are not qualified to train homeowners in aerobic system maintenance.

HB 2510 specifies that the manufacturer or installer is responsible for training a homeowner desiring aerobic system training. No changes were made in response to this comment.

Snowden commented that homeowner training should be no less than six hours.

The commission agrees and has revised §285.7(c)(4)(A)(i)(III)(-b-) to require six hours of homeowner training.

Myrtle Springs Septic Systems commented that the rules should require proof that the homeowner actually received six hours of aerobic system training in maintenance.

The rules require a letter from the trainer (manufacturer or installer) be sent to the permitting authority that the homeowner received and completed the required (six hours) training. No changes were made in response to this comment.

Environmental made a recommendation that homeowners be registered with the commission in the same manner as maintenance providers. Additionally, this registration would be used to track homeowner compliance with maintenance requirements.

Local permitting authorities will be tracking homeowners who have successfully completed training. This will be documented though the required letter provided to the permitting authority from either the manufacturer or installer who trained the homeowner. No changes were made in response to this comment.

Clearstream commented the statute requires that a homeowner has 30 days to receive training from a certified installer after the purchase of a residence with an aerobic system maintained by the previous owner. Otherwise, the new homeowner must have a maintenance contract. Conversely, TOWA and Whitt commented that the requirement for both the installer and manufacturer to train the homeowner be amended to only require that the manufacturer train the homeowner within the 30-day period.

The commission acknowledges the language in the statute. A homeowner's ability to receive training after taking possession of a residence with an existing aerobic system is the same as any other homeowner with an aerobic system. No changes were made in response to this comment.

Whitt suggested that the commission require homeowners to have auto dialers which also alert the permitting authority of system malfunctions.

Section 285.7(d)(3) allows electronic monitoring and automatic telephone or radio access which notifies the maintenance company of system or component failure, including the amount of system disinfection. In doing so, the number of maintenance inspections may be reduced from three to two per year. This remains an option and no changes were made in response to this comment.

Harris County and Snowden commented that the commission was not given statutory authority to require manufacturers and installers to provide parts to homeowners who maintain their own aerobic system. Conversely, Whitt commented that homeowners be required to provide proof that parts within an aerobic treatment unit were replaced with the correct parts.

The commission agrees with this statement on face value. However, requiring the availability of replacement parts allows the homeowner to maintain the aerobic system with components which were certified during the National Sanitation Foundation (NSF) testing process and under which state approval was granted. The proposed rules, in §285.7(d)(4), stated that the manufacturer shall make replacement parts available and has been changed to state that both the manufacturer and installer shall make replacement parts available. Additionally, these requirements are reflected in §285.61 (relating to Duties and Responsibilities of Installers) and §285.65 (relating to Suspension or Revocation of License or Registration). No other changes were made in response to this comment.

Brazos Wastewater, TOWA, Travis County, Whitt, and one individual commented that inspections of homeowner-maintained aerobic systems should be more frequent than once every five years.

This requirement is part of the statute and states that a routine inspection cannot be made more than once every five years. However, both the current and proposed rules state that a permitting authority can inspect any OSSF if there is a complaint or a nuisance condition exists. No changes were made in response to this comment.

TOWA recommended an inspection within the initial 12 months of a system maintained by a homeowner.

The commission responds that both the current and proposed rules state that a permitting authority can inspect any OSSF if there is a complaint or a nuisance condition exists. No changes were made in response to this comment.

Travis County recommended adding the word "minimum" to §285.33 where disposal area is calculated.

The commission agrees and has modified the wording for area calculations within the sections open for revision.

Snowden recommended that the commission exclude drip irrigation from mound systems and not allow soil substitution systems when there are untested, unproven standards.

The commission disagrees because no evidence was provided which defines and supports this comment. No changes were made in response to this comment.

Travis County commented that 18 inches of soil is insufficient for the soil's filtering ability.

The commission disagrees with this comment. The combination of 12 inches of soil with less than 30% gravel, and a minimum of six inches of imported soil, combined with a pressure distribution system is already as stringent as current requirements for similar systems, such as low-pressure dosing systems. No changes were made in response to this comment.

Travis County commented that the length of the distribution calculation will encourage designs which extend into the side slopes.

The commission agrees and §285.33(d)(3)(E) has been revised to exclude the pipe within 12 inches of the side slopes.

Travis County commented that the words "covered piping" are unnecessary in §285.33(d)(3)(E)(ii)(II).

The commission agrees with the comment and has revised §285.33(d)(3)(E)(ii)(II).

Travis County commented that §285.33(d)(3)(E)(iii) requires a 7:1 side slope length to width ratio which is excessive and recommends a ratio of 4:1.

The commission agrees that a smaller length to width ratio is acceptable for certain sites. Section 285.33(d)(3)(E)(iii) is revised to define situations where the 4:1 ratio is allowed.

Travis County commented that while §285.33(d)(3)(E)(vi) requires dosing holes no more than four feet apart, three feet distance would be more appropriate.

The commission agrees with the comment and §285.33(d)(3)(E)(vi) has been revised to reflect a three-foot spacing.

Travis County commented that §285.33(d)(3)(F)(ii) requires an area credited toward a basal area must include all areas below the distribution system. Travis County recommends "may" instead of "must" in order to guide the designer into using only the portion of the mound footprint that the designer has determined as appropriate.

The commission generally agrees with this comment and has removed the word "must" from the proposed rules.

Travis County recommended low-pressure dosing of soil substitution drainfields due to the inability of gravity flow to provide a uniform loading.

The commission disagrees with the comment. The requirement of two feet of imported soil combined with gravity distribution is consistent with existing requirements for standard subsurface disposal systems.

Travis County commented that soil substitution in certain soil strata is an incorrect use of the design.

The commission agrees and has changed §285.33(4) to include "highly permeable" before "fractured rock" and before "fissured rock." Additionally, §285.33(4)(E) was amended where it states "permeable fractured and fissured rock" to "highly permeable fractured and fissured rock."

Environmental and Whitt commented that the potential exists for installers to sell certificates to homeowners without adequately training the homeowner. Additionally, Meiners commented that homeowners may falsify reporting data to permitting authorities.

The commission agrees that the potential exists, but there are a number of requirements in both the existing and proposed rules to enforce against individuals who falsify documents and provide inadequate training. No changes were made in response to this comment.

TOWA commented that a sole proprietorship may have more than one employee and recommended §285.64(2) be amended to better reflect the statute.

The commission agrees with TOWA that regardless of the number of employees in a sole proprietorship, there must be at least one Installer II who is certified by the manufacturer to perform maintenance and registered by the commission. The revision to §285.64(2) has been made.

State Representative Dennis Bonnen commented that revoking an installer's license if they fail to meet the deadline in training a homeowner even once is ". . . overly harsh and will only decrease the number of people providing this service."

The commission responds that the proposed rules state, in §285.65(b), that ". . . revocation may . . ." (italics added) be considered for an installer's license for failing to provide proper maintenance training to an owner of an aerobic OSSF in a timely manner. The commission responds that this is an enforcement-related process subject to discovery and evidence which does not automatically revoke an installer's license. No changes were made in response to this comment.

TOWA commented that the commission consider requiring maintenance providers have proof of liability insurance as well as stocking approved parts and supplies for aerobic systems which they maintain in order to repair a noncompliant system within 48 hours.

The commission responds that liability insurance and what constitutes a sufficient amount of parts and supplies is a business decision to be made by the maintenance company's owner and is not part of the Chapter 285 rules. No changes were made in response to this comment.

AAA and one individual commented that the commission should impose fines for homeowners who do not properly maintain their own aerobic systems.

THSC, §366.0515(j), was amended in HB 2510 to include the requirement for an owner to have a maintenance contract if the owner's system is a nuisance or has failed a periodic inspection. The rules reflect this in §285.70. However, no fines are proposed for homeowners. No changes were made in response to this comment.

A.C.E., Brazos, and one individual commented that authorized agents will not be able to adequately inspect and enforce homeowners who maintain their own aerobic systems. Additionally, A.C.E., Meiners, and one individual commented that systems maintained by homeowners will result in an increase in complaints for authorized agents to investigate.

This rulemaking does not change the authorized agent's responsibilities in enforcing its permitting function. Additionally, provisions for enforcement against homeowners who violate the regulations are provided in §285.70 and §285.71. No changes were made in response to this comment.

Travis County recommended that Figure 4, in §285.90, be revised to include both a soil substitution bed section using gravel media and one or two mound cross sections.

The commission anticipates revising and adding significantly more information to Figure 4 during the next revision to Chapter 285. No changes were made in response to this comment.

Snowden recommended that the commission revise Table XII, in §285.91, to include septic drip systems.

A revision to Table XII is beyond the scope of this rulemaking. No changes were made in response to this comment.

Subchapter A. GENERAL PROVISIONS

30 TAC §285.2, §285.7

STATUTORY AUTHORITY

The amendments are adopted under the authority granted to the commission by the Texas Legislature in Texas Water Code (TWC), Chapter 37, and THSC, Chapter 366. The amendments are also adopted under the general authority granted in TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; TWC, §5.102, which establishes the commission's authority necessary to carry out its jurisdiction; TWC, §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; and TWC, §7.002, which authorizes the commission to enforce provisions of the TWC and the THSC.

The adopted amendments implement TWC, §37.002, which requires the commission to adopt rules to establish registration requirements for maintenance providers that will service and maintain on-site sewage disposal systems using aerobic treatment under THSC, §366.0515, and to impose administrative and criminal penalties under TWC, §§7.173 - 7.175.

§285.7.Maintenance Requirements.

(a) Maintenance requirements. Maintenance requirements for all on-site sewage facilities (OSSFs) are identified in §285.91(12) of this title (relating to Tables).

(b) Maintenance company.

(1) An individual must be certified by the manufacturer of an OSSF using aerobic treatment to maintain the system under a maintenance contract with the owner of the system or to provide training to the owner in maintenance of the system. A manufacturer may not unreasonably withhold certification and, except as otherwise provided by this subsection, must offer the certification to individuals who are not employees of the manufacturer on the same terms as the manufacturer offers the certification to the manufacturer's employees.

(A) Additionally, the individual shall:

(i) satisfactorily complete an executive director-approved course for persons who provide aerobic system maintenance. This course must be a minimum of 16 classroom hours of instruction in public health and safety, proper maintenance procedures, and recordkeeping and reporting. This course must have been approved by the executive director after September 1, 2005;

(ii) be employed by a maintenance company in which at least one employee holds an Installer II license;

(iii) meet all of the manufacturer's criteria and requirements for entering into a business relationship; and

(iv) satisfactorily complete any other reasonable requirements imposed for certification by the manufacturer.

(B) A person providing maintenance with a valid wastewater Class D license on or before August 31, 2006, may continue to do so until August 31, 2008, provided that person also satisfies the requirements of subparagraph (A)(i), (iii), and (iv) of this title.

(2) For nonstandard systems, an individual providing maintenance shall be trained by the professional engineer or professional sanitarian responsible for preparing the planning materials for a nonstandard system.

(3) The maintenance company and the individual certified by the manufacturer will be responsible for fulfilling the requirements of the maintenance contract.

(c) Maintenance contracts. OSSFs required to have maintenance contracts are identified in §285.91(12) of this title. The OSSF shall be maintained and tested by the maintenance company holding a maintenance contract.

(1) Contract provisions. The OSSF maintenance contract shall, at a minimum:

(A) list items that are covered by the contract;

(B) specify a time frame in which the maintenance company will visit the property in response to a complaint by the property owner regarding the operation of the system;

(C) specify the name of the individual employed by the maintenance company who is certified by the manufacturer of the system and is responsible for fulfilling the terms of the maintenance contract;

(D) identify the frequency of routine maintenance and the frequency of the required testing and reporting; and

(E) identify who is responsible for maintaining the disinfection unit.

(2) Contract submittals. Unless excepted by paragraph (4) of this subsection, a copy of the signed maintenance contract shall be provided by the owner to the permitting authority before the authorization to construct is issued. Before the current contract expires, the owner of an OSSF is required to have a new maintenance contract signed. A copy of a new contract shall be submitted to the permitting authority at least 30 days before the contract expires.

(A) Initial maintenance contract. The initial written maintenance contract shall be effective for at least two years from the date the OSSF is first used. For a new single family dwelling, this date is the date of sale by the builder. For an existing single family dwelling this date is the date the notice of approval is issued by the permitting authority.

(B) Ongoing maintenance contract. After the expiration of the two-year initial maintenance contract, the owner shall have ongoing maintenance performed by either the original maintenance company or another maintenance company qualified under subsection (b)(1) of this section, unless the exceptions in paragraph (4) of this subsection apply.

(3) Amendments or terminations.

(A) If the maintenance company changes the individual certified by the manufacturer under subsection (b) (1)(A) of this section, the maintenance company shall initiate an amendment of the contract. The contract shall be amended within 30 days after the change in personnel. The permitting authority shall be provided with a copy of the amended contract within 30 days after the amended contract is signed.

(B) If the maintenance company discontinues the maintenance contract, the maintenance company shall notify, in writing, the permitting authority, the manufacturer, and the owner at least 30 days before the date service will cease.

(C) If the owner discontinues the maintenance contract, the owner shall notify, in writing, the permitting authority, the manufacturer, and the maintenance company at least 30 days before the date service will cease.

(D) If a maintenance contract is discontinued or terminated, the owner shall contract with another maintenance company and provide the permitting authority with a copy of the new signed maintenance contract no later than 30 days after termination, unless the owner meets the requirements of paragraph (4) of this subsection.

(4) Exceptions to maintenance contract. At the end of the initial two-year maintenance period, the owner of an aerobic treatment system for a single family residence shall either maintain the system personally or obtain a new maintenance contract.

(A) If the owner of an OSSF using aerobic treatment for a single-family residence elects to maintain the system directly and in accordance with §30.244(a) of this title (relating to Exemptions), the owner must obtain specific on-site maintenance training for the system from either the manufacturer or an installer who has been certified by the manufacturer.

(i) Training for the homeowner of an aerobic OSSF must be given within 30 calendar days of the date when requested by the homeowner. Additionally, this training must be completed a minimum of 30 days prior to the end of the existing maintenance contract.

(I) A manufacturer shall train the owner of the aerobic OSSF when requested by the owner, under the time frames described in this subsection. Failure to provide the owner with approved training within the specified time frame may result in removal of the manufacturer's product(s) from the list of approved systems.

(II) An installer shall train the owner of the aerobic OSSF when requested by the owner, under the time frames described in this subsection. Failure to provide the owner with approved training within the specified time frame may result in penalties to the installer, as described in §285.61 of this title (relating to Duties and Responsibilities of Installers). These penalties may include revocation of the installer's license and registration as a maintenance provider.

(III) The specific on-site maintenance training for owners of aerobic systems must:

(-a-) have been previously approved by the executive director;

(-b-) provide for six hours of training;

(-c-) be provided and completed in a timely manner that allows the owner to be trained and comply with the requirements of training and maintenance of this subsection and §285.70 of this title (relating to Duties of Owners With Malfunctioning OSSFs);

(-d-) include the importance to public health and safety of proper maintenance of the system; and

(-e-) a demonstration of the procedure for performing scheduled maintenance.

(ii) Within 30 days after the owner's completion of the training, the manufacturer or installer shall provide both the owner and the permitting authority with a written certificate or letter, signed by the manufacturer or installer, stating that the owner has received and completed the required training.

(B) Maintenance of an aerobic system by a homeowner is subject to any inspection and reporting requirements imposed by an authorized agent or the commission applicable to a maintenance company that contracts to maintain a system.

(C) If the residence is sold, the new homeowner, not later than the 30th day after the date the owner takes possession of the property, must obtain the training required by this subsection from either an installer certified by the manufacturer of the system or the manufacturer. If the homeowner does not request training, then the homeowner must contract with a maintenance company for the maintenance of the system. However, this requirement does not limit a homeowner's ability to both receive training and maintain the homeowner's aerobic system as required in this paragraph.

(d) Testing and reporting. OSSFs that must be tested are identified in §285.91(12) of this title.

(1) The maintenance company, or the homeowner, if applicable under subsection (c)(4) of this section, shall test and report for each system as required in §285.90(3) of this title (relating to Figures) and §285.91(4) of this title. The report must:

(A) include any responses to owner complaints, the results of the maintenance company's findings or the owner's findings, and the test results; and

(B) be submitted to the permitting authority and, if applicable, the owner within 14 days after the date the test is performed.

(2) To provide the owner with a record of the maintenance check, the maintenance company shall install a weather resistant tag, or some other form of weather resistant identification, on the system at the beginning of each maintenance contract. This identification shall:

(A) identify the maintenance company;

(B) list the telephone number of the maintenance company;

(C) specify the start date of the contract; and

(D) be either punched or indelibly marked with the date the system was checked at the time of each maintenance check, including any maintenance check in response to owner complaints.

(3) The number of required tests may be reduced to two per year for all systems having electronic monitoring and automatic telephone or radio access that will notify the maintenance company, or the owner if applicable under subsection (c)(4) of this section, of system or components failure and will monitor the amount of disinfection in the system. The maintenance company shall be responsible for ensuring that the electronic monitoring and automatic telephone or radio access systems are working properly.

(4) The manufacturer and the installer of the installed on-site aerobic system shall make available to the homeowner all replacement parts for that aerobic system to any homeowner who elects to maintain the on-site aerobic system as identified in subsection (c)(4) of this section. Failure to do so may result in removal of the manufacturer's product(s) from the list of approved systems.

(5) An authorized agent or the commission may routinely inspect an on-site sewage system using aerobic treatment for a single-family residence that is maintained directly by the owner of the system not more than once every five years.

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 July 14, 2006.

TRD-200603747

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 24, 2006

For further information, please call: (512) 239-0177

Subchapter D. PLANNING, CONSTRUCTION, AND INSTALLATION STANDARDS FOR OSSFS

30 TAC §285.33

STATUTORY AUTHORITY

The amendment is adopted under the authority granted to the commission by the Texas Legislature in TWC, Chapter 37, and THSC, Chapter 366. The amendment is also adopted under the general authority granted in TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; TWC, §5.102, which establishes the commission's authority necessary to carry out its jurisdiction; TWC, §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; and TWC, §7.002, which authorizes the commission to enforce provisions of the TWC and the THSC.

The adopted amendment implements TWC, §37.002, which requires the commission to adopt rules to establish registration requirements for maintenance providers that will service and maintain on-site sewage disposal systems using aerobic treatment under THSC, §366.0515, and to impose administrative and criminal penalties under TWC, §§7.173 - 7.175.

§285.33.Criteria for Effluent Disposal Systems.

(a) General requirements.

(1) All disposal systems in this section shall have an approved treatment system as specified in §285.32(b) - (d) of this title (relating to Criteria for Sewage Treatment Systems).

(2) All criteria in this section shall be met before the permitting authority issues an authorization to construct.

(3) The pipe between all treatment tanks and the pipe from the final treatment tank to a gravity disposal system shall be a minimum of three inches in diameter and be American Society for Testing and Materials (ASTM) 3034, Standard dimension ratio (SDR) 35 polyvinyl chloride (PVC) pipe or a pipe with an equivalent or stronger pipe stiffness at a 5% deflection. The pipe must maintain a continuous fall to the disposal system.

(4) The pipe from the final treatment tank to a gravity disposal system shall be a minimum of five feet in length.

(b) Standard disposal systems. Acceptable standard disposal methods shall consist of a drainfield to disperse the effluent either into adjacent soil (absorptive) or into the surrounding air through evapotranspiration (evaporation and transpiration).

(1) Absorptive drainfield. An absorptive drainfield shall only be used in suitable soil. There shall be two feet of suitable soil from the bottom of the excavation to either a restrictive horizon or to groundwater.

(A) Excavation. The excavation must be made in suitable soils as described in §285.31(b) of this title (relating to Selection Criteria for Treatment and Disposal Systems).

(i) The excavation shall be at least 18 inches deep but shall not exceed a depth of either three feet or six inches below the soil freeze depth, whichever is deeper. Single excavations shall not exceed 150 feet.

(ii) In areas of the state where annual precipitation is less than 26 inches per year (as identified in the Climatic Atlas of Texas , (1983) published by the Texas Department of Water Resources or other standards approved by the executive director), and suitable soils (Class Ib, II, or III) lie below unsuitable soil caps, the maximum permissible excavation depth shall be five feet.

(iii) Multiple excavations must be separated horizontally by at least three feet of undisturbed soil. The sidewalls and bottom of the excavation must be scarified as needed. When there are multiple excavations, it is recommended that the ends be looped together.

(iv) The bottom of the excavation shall be not less than 18 inches in width.

(v) The bottom of the excavation shall be level to within one inch over each 25 feet of excavation or within three inches over the entire excavation, whichever is less.

(vi) If the borings or backhoe pits excavated during the site evaluation encounter a rock horizon and the site evaluation shows that there is both suitable soil from the bottom of the rock horizon to two feet below the bottom of the proposed excavation and no groundwater anywhere within two feet of the bottom of the proposed excavation, a standard subsurface disposal system may be used, providing the following are met.

(I) The depth of the excavation shall comply with clause (i) of this subparagraph.

(II) The rock horizon shall be at least six inches above the bottom of the excavation.

(III) Surface runoff shall be prevented from flowing over the disposal area.

(IV) Subsurface flow along the top of the rock horizon shall be prevented from flowing into the excavation.

(V) The sidewall area will not be counted toward the required absorptive area.

(VI) The formulas in clause (vii)(I) - (III) of this subparagraph shall be adjusted so that no credit is given for sidewall area.

(VII) No single pipe drainfields on sloping ground as shown in §285.90(5) of this title (relating to Figures) or no systems using serial loading shall be used.

(vii) The size of the excavation shall be calculated using data from §285.91(1) and (3) of this title (relating to Tables). The soil application rate is based on the most restrictive horizon along the media, or within two feet below the bottom of the excavation. The formula A = Q/Ra shall be used to determine the total absorptive area where:

Figure: 30 TAC §285.33(b)(1)(A)(vii) (No change.)

(I) The absorptive area shall be calculated by adding the bottom area (L x W) of the excavation to the total absorptive area along the excavated perimeter 2(L+W), (in feet) multiplied by one foot.

Figure: 30 TAC §285.33(b)(1)(A)(vii)(I) (No change.)

(II) The length of the excavation may be determined as follows when the area and width are known.

Figure: 30 TAC §285.33(b)(1)(A)(vii)(II) (No change.)

(III) For excavations three feet wide or less, use the following formula, or §285.91(8) of this title to determine L.

Figure: 30 TAC §285.33(b)(1)(A)(vii)(III) (No change.)

(B) Media. The media shall consist of clean, washed and graded gravel, broken concrete, rock, crushed stone, chipped tires, or similar aggregate that is generally one uniform size and approved by the executive director. The size of the media must range from 0.75 - 2.0 inches as measured along its greatest dimension except as noted in clause (i) of this subparagraph.

(i) If chipped tires are used:

(I) a geotextile fabric heavier than specified in subparagraph (E) of this paragraph must be used; and

(II) the size of the chipped tires must not exceed three inches as measured along their greatest dimension.

(ii) Soft media such as oyster shell and soft limestone shall not be used.

(C) Drainline. The drainline shall be constructed of perforated distribution pipe and fittings in compliance with any one of the following specifications:

(i) three- or four-inch diameter PVC pipe with an SDR of 35 or stronger;

(ii) four-inch diameter corrugated polyethylene, ASTM F405 in rigid ten foot joints;

(iii) three- or four-inch diameter polyethylene smoothwall, ASTM F810;

(iv) three- or four-inch diameter PVC ASTM D2729 pipe;

(v) three- or four-inch diameter polyethylene ASTM F892 corrugated pipe with a smoothwall interior and fittings; or

(vi) any other pipe approved by the executive director.

(D) Drainline installation requirements. The drainline shall be placed in the media with at least six inches of media between the bottom of the excavation and the bottom of the drainline. The drainline shall be completely covered by the media and the drainline perforations shall be below the horizontal center line of the pipe. For typical drainfield configurations, see §285.90(5) of this title. For excavations greater than four feet in width, the maximum distance between parallel drainlines shall be four feet (center to center). Multiple drainlines shall be manifolded together with solid or perforated pipe. Additionally, the ends of the multiple drainlines opposite the manifolded end shall either be manifolded together with a solid line, looped together using a perforated pipe and media, or capped.

(E) Permeable soil barrier. Geotextile fabric shall be used as the permeable soil barrier and shall be placed between the top of the media and the excavation backfill. Geotextile fabric shall conform to the following specifications for unwoven, spun-bounded polypropylene, polyester, or nylon filter wrap.

Figure: 30 TAC §285.33(b)(1)(E) (No change.)

(F) Backfilling. Only Class Ib, II, or III soils as described in §285.30 of this title (relating to Site Evaluation) shall be used for backfill. Class Ia and IV soils are specifically prohibited for use as a backfill material. The backfill material shall be mounded over the excavated area so that the center of the backfilled area slopes down to the outer perimeter of the excavated area to allow for settling. Surface runoff impacting the disposal area is not permitted and the diversion method shall be addressed during development of the planning materials.

(G) Drainfields on irregular terrain. Where the ground slope is greater than 15% but less than 30%, a multiple line drainfield may be constructed along descending contours as shown in §285.90(5) of this title. An overflow line shall be provided from the upper excavations to the lower excavations. The overflow line shall be constructed from solid pipe with an SDR of 35 or stronger, and the excavation carrying the overflow pipe shall be backfilled with soil only.

(H) Drainfield plans. A number of sketches, specifications, and details for drainfield construction are provided in §285.90(4) and (5) of this title.

(2) Evapotranspirative (ET) system. An ET system may be used in soils which are classified as unsuitable for standard subsurface absorption systems according to §285.31(b) of this title with respect to texture, restrictive horizons, or groundwater. Water saving devices must be used if an ET system is to be installed. ET systems shall only be used in areas of the state where the annual average evaporation exceeds the annual rainfall. Evaporation data is provided in §285.91(7) of this title.

(A) Liners. An impervious liner shall be used between the excavated surface and the ET system in all Class Ia soils, where seasonal groundwater tables penetrate the excavation, and where a minimum of two feet of suitable soil does not exist between the excavated surface and either a restrictive horizon or groundwater. Liners shall be rubber, plastic, reinforced concrete, gunite, or compacted clay (one foot thick or more). If the liner is rubber or plastic, it must be impervious, and each layer must be at least 20 mils thick. Rubber or plastic liners must be protected from exposed rocks and stones by covering the excavated surface with a uniform sand cushion at least four inches thick. Clay liners shall have a permeability of 10 -7 centimeters/second or less, as tested by a certified soil laboratory.

(B) ET system sizing. The following formula shall be used to calculate the top surface area of an ET system.

Figure: 30 TAC §285.33(b)(2)(B) (No change.)

The owner of the ET system shall be advised by the person preparing the planning materials of the limits placed on the system by the Q selected. If the Q is less than required by §285.91(3) of this title, the flow rate shall be included as a condition to the permit, and stated in an affidavit properly filed and recorded in the deed records of the county as specified in §285.3(b)(3) of this title (relating to General Requirements).

(C) Backfill material. Backfill material shall consist of Class II soil as described in §285.30 of this title. All drainlines must be surrounded by a minimum of one foot of media. Backfill shall be used to fill the excavation between the media to allow the backfill material to contact the bottom of the excavation.

(D) Vegetative cover for transpiration. The final grade shall be covered with vegetation fully capable of taking maximum advantage of transpiration. Evergreen bushes with shallow root systems may be planted in the disposal area to assist in water uptake. Grasses with dormant periods shall be overseeded to provide year-round transpiration.

(E) ET systems. ET systems shall be divided into two or more equal excavations connected by flow control valves. One excavation may be removed from service for an extended period of time to allow it to dry out and decompose biological material which might plug the excavation. If one of the excavations is removed from service, the daily water usage must be reduced to prevent overloading of the excavation(s) still in operation. Normally, an excavation must be removed from service for two to three dry months for biological breakdown to occur.

(F) ET system plans. A number of sketches for ET system construction are provided in §285.90(4) and (5) of this title.

(3) Pumped effluent drainfield. Pumped effluent drainfields shall use the specifications for low- pressure dosed drainfields described in subsection (d)(1) of this section, with the following exceptions.

(A) Applicability. If the slope of the site is greater than 2.0%, pumped effluent drainfields shall not be used. Pumped effluent drainfields may only be used by single family dwellings.

(B) Length of distribution pipe. There shall be at least 1,000 linear feet of perforated pipe for a two bedroom single family dwelling. For each additional bedroom, there shall be an additional 400 linear feet of perforated pipe. No individual distribution line shall exceed 70 feet in length from the header.

(C) Excavation width and horizontal separation. The excavated area shall be at least six inches wide. There shall be at least three feet of separation between trenches.

(D) Lateral depth and vertical separation. All drainfield laterals shall be between 18 inches and three feet deep. There shall be a minimum vertical separation distance of one foot from the bottom of the excavation to a restrictive horizon, and a minimum vertical separation of two feet from the bottom of the excavation to groundwater.

(E) Media. Each dosing pipe shall be placed with the drain holes facing down and placed on top of at least six inches of media (pea gravel or media up to two inches measured along its greatest dimension).

(F) Pipe and hole size. The distribution (dosing) and manifold (header) pipe shall be 1.25 - 1.5 inches in diameter. The manifold may have a diameter larger than the distribution pipe, but shall not exceed 1.5 inches in diameter. Distribution (dosing) pipe holes shall be 3/16 - 1/4 inch in diameter and shall be spaced five feet apart.

(G) Pump size. Pumped effluent drainfields shall use at least a 1/2 horsepower pump.

(H) Backfilling. Only Class Ib, II, or III soils as described in §285.30(b)(1)(A) of this title shall be used for backfill.

(c) Proprietary disposal systems.

(1) Gravel-less drainfield piping. Gravel-less pipe may be used only on sites suitable for standard subsurface sewage disposal methods. Gravel-less pipe shall be eight-inch or ten-inch diameter corrugated perforated polyethylene pipe. The pipe shall be enclosed in a layer of unwoven spun- bonded polypropylene, polyester, or nylon filter wrap. Gravel-less pipe shall meet ASTM F-667 Standard Specifications for large diameter corrugated high density polyethylene (ASTM D 1248) tubing. The filter cloth must meet the same material specifications as described under subsection (b)(1)(E) of this section.

(A) Planning parameters. Gravel-less drainfield pipe may be substituted for drainline pipe in both absorptive and ET systems. When gravel-less pipe is substituted, media will not be required. ET systems shall be backfilled with Class II soils only. All other planning parameters for absorptive or ET systems apply to drainfields using gravel-less pipe.

(B) Installation. The connection from the solid line leaving the treatment tank to the gravel-less line shall be made by using an eight or ten-inch offset connector. The gravel-less line shall be laid level, the continuous stripe shall be up, and the lines shall be joined together with couplings. A filter cloth must be pulled over the joint to eliminate soil infiltration. The gravel-less pipe must be held in place during initial backfilling to prevent movement of the pipe. The end of each gravel-less line shall have an end cap and an inspection port. The inspection port shall allow for easy monitoring of the amount of sludge or suspended solids in the line, and allow the distribution lines to be back-flushed.

(C) Drainfield sizing. To determine appropriate drainfield sizing, use a drainfield width of W = 2.0 feet for an eight-inch diameter gravel-less pipe, and an excavation width of W = 2.5 for a ten-inch gravel-less pipe.

Figure: 30 TAC §285.33(c)(1)(C) (No change.)

(2) Leaching chambers. Leaching chambers are bottomless chambers that are installed in a drainfield excavation with the open bottom of the chamber in direct contact with the excavation. The ends of the chamber rows shall be linked together with non-perforated sewer pipe. The chambers shall completely cover the excavation, and adjacent chambers must be in contact with each other in such a manner that the chambers will not separate. To obtain the reduction in drainfield size allowed in subparagraph (A)(i) and (ii) of this paragraph for excavations wider than the chambers, the chambers shall be placed edge to edge.

(A) The following formulas shall be used to determine the length of an excavation using leaching chambers.

(i) The following formula is used for leaching chambers without water saving devices.

Figure: 30 TAC §285.33(c)(2)(A)(i) (No change.)

(ii) The following formula is used for leaching chambers with water saving devices.

Figure: 30 TAC §285.33(c)(2)(A)(ii) (No change.)

(B) Leaching chambers shall not be used for absorptive drainfields in Class Ia or IV soils. Leaching chambers may be used instead of media in ET systems, low-pressure dosed drainfields, and soil substitution drainfields; however, the size of the drainfield shall not be reduced from the required area.

(C) Backfill covering leaching chambers shall be Class Ib, II, or III soil.

(3) Drip irrigation. Drip irrigation systems using secondary treatment may be used in all soil classes including Class IV soils. The system must be equipped with a filtering device capable of filtering particles larger than 100 microns and that meets the manufacturer's requirements.

(A) Drainfield layout. The drainfield shall consist of a matrix of small-diameter pressurized lines, buried at least six inches deep, and pressure reducing emitters spaced at a maximum of 30-inch intervals. The pressure reducing emitter shall restrict the flow of effluent to a flow rate low enough to ensure equal distribution of effluent throughout the drainfield.

(B) Effluent quality. The treatment preceding a drip irrigation system shall treat the wastewater to secondary treatment as described in §285.32(e) of this title unless the drip irrigation system has been approved by the executive director as a proprietary disposal system without the use of secondary treatment.

(C) System flushing. Systems must be equipped to flush the contents of the lines back to the pretreatment unit when intermittent flushing is used. If continuous flushing is used during the pumping cycle, the contents of the lines must be returned to the pump tank.

(D) Loading rates. Pressure reducing emitters can be used in all classes of soils using loading rates specified in §285.91(1) of this title. Pressure reducing emitters are assumed to wet four square feet of absorptive area per emitter; however, overlapping areas shall only be counted once toward absorptive area requirements. The loading rate shall be based on the most restrictive soil horizon within one foot of the pressure reducing emitter. When solid rock is less than 12 inches below the pressure reducing emitter, the loading rate shall be based on Class IV soils.

(E) Vertical separation distance. There shall be a minimum of one foot of soil between the pressure reducing emitter and groundwater and six inches between the pressure reducing emitter and solid rock, or fractured rock. For proprietary disposal systems that do not pretreat to secondary treatment, there shall be two feet of soil between the groundwater and pressure reducing emitter and one foot of soil between solid rock or fractured rock and the pressure reducing emitter.

(F) Labeling or listing. All drip irrigation system devices shall either be labeled by the manufacturer as suitable for use with domestic sewage, or be on the list of approved devices maintained by the executive director according to §285.32(c)(4) of this title.

(4) Approval of proprietary disposal systems. All proprietary disposal systems, other than those described in this section, shall be approved by the executive director before they may be used. Proprietary disposal systems shall be approved by the executive director using the procedures established in §285.32(c)(4)(B) of this title.

(d) Nonstandard disposal systems. All disposal systems not described or defined in subsections (b) and (c) of this section are nonstandard disposal systems. Planning materials for nonstandard disposal systems must be developed by a professional engineer or professional sanitarian using basic engineering and scientific principles. The planning materials for paragraphs (1) - (5) of this subsection shall be submitted to the permitting authority and the permitting authority shall review and either approve or disapprove them on a case-by-case basis according to §285.5 of this title (relating to Submittal Requirements for Planning Materials). Electrical wiring for nonstandard disposal systems shall be installed according to §285.34(c) of this title (relating to Other Requirements). Upon approval of the planning materials, an authorization to construct will be issued by the permitting authority. Approval for a nonstandard disposal system is limited to the specific system described in the planning materials for the specific location. The systems identified in paragraphs (1) - (5) of this subsection must meet these requirements, in addition to the requirements identified for each specific system in this section.

(1) Low-pressure dosed drainfield. Effluent from this type of system shall be pumped, under low pressure, into a solid wall force main and then into a perforated distribution pipe installed within the drainfield area.

(A) The effluent pump in the pump tank must be capable of an operating range that will assure that effluent is delivered to the most distant point of the perforated piping network, yet not be excessive to the point that blowouts occur.

(B) A start/stop switch or timer must be included in the system to control the dosing pump. An audible and visible high water alarm, on an electric circuit separate from the pump, must be provided.

(C) Pressure dosing systems shall be installed according to either design criteria in the North Carolina State University Sea Grant College Publication UNC-S82-03 (1982) or other publications containing criteria or data on pressure dosed systems which are acceptable to the permitting authority. Additionally, the following sizing parameters are required for all low-pressure dosed drainfields and shall be used in place of the sizing parameters in the North Carolina State University Sea Grant College Publication or other acceptable publications.

(i) The low-pressure dosed drainfield area shall be sized according to the effluent loading rates in §285.91(1) of this title and the wastewater usage rates in §285.91(3) of this title. The effluent loading rate (Ra) in the formula in §285.91(1) of this title shall be based on the most restrictive horizon one foot below the bottom of the excavation. Excavated areas can be as close as three feet apart, measured center to center. All excavations shall be at least six inches wide. To determine the length of the excavation, use the following formulas, where L = excavation length, and A = absorptive area.

(I) If the media in the excavation is at least one foot deep, the length of the excavation is L = A/(w+2) where:

(-a-) w = the width of the excavation for excavations one foot wide or greater; or

(-b-) w = 1 for all excavations less than one foot wide.

(II) If the media in the excavation is less than one foot deep, the length of the excavation is L = A/(w + 2H), where H = the depth of the media in feet and:

(-a-) w = the width of the excavation for excavations one foot wide or greater; or

(-b-) w = 1 for all excavations less than one foot wide.

(ii) Each dosing pipe shall be placed with the drain holes facing down and placed on top of at least six inches of media (pea gravel or media up to two inches measured along the greatest dimension).

(iii) Geotextile fabric meeting the criteria in subsection (b)(1)(E) of this section shall be placed over the media. The excavation shall be backfilled with Class Ib, II, or III soil.

(iv) There shall be a minimum of one foot of soil between the bottom of the excavation and solid or fractured rock. There shall be a minimum of two feet of soil between the bottom of the excavation and groundwater.

(2) Surface application systems. Surface application systems include those systems that spray treated effluent onto the ground.

(A) Acceptable surface application areas. Land acceptable for surface application shall have a flat terrain (with less than or equal to 15% slope) and shall be covered with grasses, evergreen shrubs, bushes, trees, or landscaped beds containing mixed vegetation. There shall be nothing in the surface application area within ten feet of the sprinkler which would interfere with the uniform application of the effluent. Sloped land (with greater than 15%) may be acceptable if it is properly landscaped and terraced to minimize runoff.

(B) Unacceptable surface application areas. Land that is used for growing food, gardens, orchards, or crops that may be used for human consumption, as well as unseeded bare ground, shall not be used for surface application.

(C) Technical report. A technical report shall be prepared for any system using surface application and shall be submitted with the planning materials required in §285.5(a) of this title. The technical report shall describe the operation of the entire on-site sewage facility OSSF system, and shall include construction drawings, calculations, and the system flow diagram. Proprietary aerobic systems may reference the executive director's approval list instead of furnishing construction drawings for the system.

(D) Effluent disinfection. Treated effluent must be disinfected before surface application. Approved disinfection methods shall include chlorination, ozonation, ultraviolet radiation, or other method approved by the executive director. Tablet or other dry chlorinators shall use calcium hypochlorite properly labeled for wastewater disinfection. The effectiveness of the disinfection procedure will be established by monitoring either the fecal coliform count or total chlorine residual from representative effluent grab samples as directed in the testing and reporting schedule. The frequency of testing, the type of tests, and the required results are shown in §285.91(4) of this title.

(E) Minimum required application area. The minimum surface application area required shall be determined by dividing the daily usage rate (Q), established in §285.91(3) of this title, by the allowable surface application rate (Ri = effective loading rate in gallons per square foot per day) found in §285.90(1) of this title or as approved by the permitting authority.

(F) Landscaping plan. Applications for surface application disposal systems shall include a landscape plan. The landscape plan shall describe, in detail, the type of vegetation to be maintained in the disposal area. Surface application systems may apply treated and disinfected effluent upon areas with existing vegetation. If any ground within the proposed surface application area does not have vegetation, that bare area shall be seeded or covered with sod before system start-up. The vegetation shall be capable of growth, before system start-up.

(G) Uniform application of effluent. Distribution pipes, sprinklers, and other application methods or devices must provide uniform distribution of treated effluent. The application rate must be adjusted so that there is no runoff.

(i) Sprinkler criteria. The maximum inlet pressure for sprinklers shall be 40 pounds per square inch. Low angle nozzles (15 degrees or less in trajectory) shall be used in the sprinklers to keep the spray stream low and reduce aerosols. If the separation distance between the property line and the edge of the surface application area is less than 20 feet, sprinkler operation shall be controlled by commercial irrigation timers set to spray between midnight and 5:00 a.m.

(ii) Planning criteria. Circular spray patterns may overlap to cover all irrigated area including rectangular shapes. The overlapped area will be counted only once toward the total application area. For large systems, multiple sprinkler heads are preferred to single gun delivery systems.

(iii) Effluent storage and pumping requirements.

(I) For systems controlled by a commercial irrigation timer and required to spray between midnight and 5:00 a.m., there shall be at least one day of storage between the alarm-on level and the pump-on level, and a storage volume of one-third the daily flow between the alarm-on level and the inlet to the pump tank.

(II) For systems not controlled by a commercial irrigation timer, the minimum dosing volume shall be at least one-half the daily flow, and a storage volume of one-third the daily flow between the alarm-on level and the inlet to the pump tank.

(III) Pump tank construction and installation shall be according to §285.34(b) of this title.

(iv) Distribution piping. Distribution piping shall be installed below the ground surface and hose bibs shall not be connected to the distribution piping outside the pump tank. An unthreaded sampling port shall be provided in the treated effluent line in the pump tank.

(v) Color coding of distribution system. Effective 365 days after the effective date of these rules, all new distribution piping, fittings, valve box covers, and sprinkler tops shall be permanently colored purple to identify the system as a reclaimed water system according to Chapter 210 of this title (relating to Use of Reclaimed Water).

(3) Mound drainfields. A mound drainfield is an absorptive drainfield constructed above the native soil surface. The mound consists of a distribution area installed within fill material placed on the native soil surface. The required area of the fill material is a function of the texture of the native soil surface, the depth of the native soil, basal area sizing considerations, and sideslope requirements. A description of mound construction, as well as construction requirements not addressed in this section can be found in the North Carolina State University Sea Grant College Publication UNC-SG-82-04 (1982).

(A) A mound drainfield shall only be installed at a site where there is at least one foot of native soil; however, approval for installation on sites with less than one foot of native soil may be granted by the permitting authority on a case-by-case basis.

(B) Mounds and mound distribution systems must be constructed with the longest dimension parallel to the contour of the site.

(C) Soil classification, loading rates (R(a)), and wastewater usage rates (Q) shall all be obtained from this chapter.

(D) The depth of soil material (with less than 30% gravel) between the bottom of the media and a restrictive horizon must be at least 1.5 feet to the restrictive horizon or two feet to groundwater. The soil material includes both the fill and the native soil.

(E) The distribution area is defined as the interface area between the media containing the distribution piping and the fill material or the native soil, if applicable. The distribution length is the dimension parallel with the contour and equivalent to the length of the distribution media which must also run parallel with the contour. The distribution lines within the distribution media must extend to 12 inches of the end of the distribution media. The distribution width is defined as the distribution area divided by the distribution length.

(i) The formula A(d) = Q/R(a) shall be used for calculating the minimum required distribution area of the mound where:

Figure: 30 TAC §285.33(d)(3)(E)(i)

(ii) The area credited toward the minimum required distribution area can be determined in either of the following ways.

(I) If the distribution area consists of a continuous six-inch layer of media over the fill, the credited area is the bottom interface area between the media and soil beneath the media.

(II) If the distribution area consists of rows of media and distribution piping, the credited area can be calculated using the formulas listed in paragraph (1)(C)(i)(I) or (II) of this subsection depending on the depth of the media.

(iii) For sites with greater than 2% slopes and solid bedrock, saturated zones, or class IV horizons within two feet of the native soil surface, the length to width ratio of the distribution area must be at least 7 : 1. For sites with greater than 2% slopes and no solid bedrock, saturated zones, or class IV horizons within two feet of the native soil surface, the length to width ratio of the distribution area must be at least 4 : 1. No length to width ratio is required on a site with 2% slope or less.

(iv) Effluent must be pressure dosed into the distribution piping to ensure equal distribution and to control application rates.

(v) If a continuous layer of media is used, the dosing lines must not be spaced more than three feet apart. If rows of media are used, the rows may be as close as three feet apart, measured edge to edge.

(vi) The dosing holes must not be greater than three feet apart.

(F) The basal area is defined as the interface area between the native soil surface and the fill material. The formula A(b) = Q/R(a) must be used for calculating the minimum required basal area of the mound where:

Figure: 30 TAC §285.33(d)(3)(F)

(i) On sites with greater than 2% slope, the area credited toward the required minimum basal area is computed by multiplying the length of the distribution system by the distance from the upslope edge of the distribution system to the downslope toe of the mound.

(ii) On sites with 2% slopes or less, the area credited toward the minimum required basal area sizing includes all areas below the distribution system as well as the side slope area on all side slope areas greater than six inches deep.

(G) Mounds shall only be installed on sites with less than 10% slope.

(H) The toe of the mound is considered the edge of the soil absorption system.

(I) The side slopes must be no steeper than three to one.

(J) There must be at least six inches of backfill over the distribution media and the mound shall be crowned to shed water.

(4) Soil substitution drainfields. Soil substitution drainfields may be constructed in Class Ia soils, highly permeable fractured rock, highly permeable fissured rock, or Class II and III soils with greater than 30% gravel.

(A) A soil substitution drainfield must not be used in Class IV soils or Class IV soils with greater than 30% gravel. Class III or IV soil shall not be used as the substituted soil in a soil substitution drainfield. There must be at least two feet of substituted soil between the bottom of the media and groundwater.

(B) A soil substitution drainfield is constructed similar to a standard absorptive drainfield except that a minimum two foot thick Class Ib or Class II soil buffer shall be placed below and on all sides of the drainfield excavation. The soil buffer must extend at least to the top of the media. The two-foot buffer area along the sides of the excavation is not credited as bottom area in calculating absorptive area. However, the interface between the media and the substituted soil is credited as absorptive area.

(C) Soil substitution drainfields must be designed to address soil compaction to prevent unlevel disposal. It is recommended that low-pressure dosing be used for effluent distribution. The edge of the substituted soil is considered the edge of the soil absorption drainfield in determining the appropriate separation distances as listed in §285.91(10) of this title.

(D) Class Ia soils do not provide adequate treatment of wastewater through soil contact. A soil substitution drainfield may be constructed in Class Ia soils in order to provide adequate soil for treatment. Absorptive area sizing must be based on the textural class of the substituted soil and must follow the formulas in subsection (b)(1)(A)(vii)(I) of this section.

(E) Highly permeable fractured and fissured rock, which contains soil in the fractures and fissures, does not provide adequate treatment of wastewater through soil contact. A soil substitution drainfield can be constructed in this permeable fractured and fissured rock in order to provide adequate soil for treatment. Absorptive area sizing must be based on the most restrictive textural class between either the native soil residing in the fractures or fissures or the substituted soil. The sizing must follow the formulas in subsection (b)(1)(A)(vii)(I) of this section.

(F) Class II and III soils with greater than 30% gravel do not provide adequate treatment of wastewater through soil contact. A soil substitution drainfield can be constructed in Class II or III soils with greater than 30% gravel in order to provide adequate soil for treatment. Absorptive area sizing must be based on the most restrictive textural class between either the non-gravel portion of the native soil or the substituted soil. The sizing must follow the formulas in subsection (b)(1)(A)(vii)(I) of this section.

(5) Drainfields following secondary treatment and disinfection. Subsurface drainfields following secondary treatment and disinfection may be constructed in Class Ia soils, fractured rock, fissured rock, or other conditions where insufficient soil depth will allow septic tank effluent to reach fractured rock or fissured rock, as long as the following conditions are met.

(A) Drainfield sizing.

(i) If the unsuitable feature is Class Ia soil, the disposal area sizing shall be based on the application rate for Class Ib soil. Some form of pressure distribution shall be used for effluent disposal.

(ii) If the unsuitable feature is fractured or fissured rock, the system sizing should be based on the application rate for Class III soil. Some form of pressure distribution system shall be used for effluent disposal.

(B) Effluent disinfection. Treated effluent must be disinfected as indicated in §285.32(e) of this title before discharging into the drainfield.

(C) Other requirements. The affidavit, maintenance, and testing and reporting requirements of §285.3(b)(3) of this title and §285.7(a) and (d) of this title (relating to Maintenance Requirements) apply to these systems.

(6) All other nonstandard disposal systems. The planning materials for all non-standard disposal systems not described in paragraphs (1) - (5) of this subsection shall be submitted to the executive director for review according to §285.5(b)(2) of this title before the systems can be installed.

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 July 14, 2006.

TRD-200603748

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 24, 2006

For further information, please call: (512) 239-0177

Subchapter F. LICENSING AND REGISTRATION REQUIREMENTS FOR INSTALLERS, APPRENTICES, DESIGNATED REPRESENTATIVES, SITE EVALUATORS, AND MAINTENANCE COMPANIES

30 TAC §§285.50, 285.61, 285.64, 285.65

STATUTORY AUTHORITY

The amendments and new sections are adopted under the authority granted to the commission by the Texas Legislature in TWC, Chapter 37, and THSC, Chapter 366. The amendments and new sections are also adopted under the general authority granted in TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; TWC, §5.102, which establishes the commission's authority necessary to carry out its jurisdiction; TWC, §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; and TWC, §7.002, which authorizes the commission to enforce provisions of the TWC and the THSC.

The adopted amendments and new sections implement TWC, §37.002, which requires the commission to adopt rules to establish registration requirements for maintenance providers that will service and maintain on-site sewage disposal systems using aerobic treatment under THSC, §366.0515, and to impose administrative and criminal penalties under TWC, §§7.173 - 7.175.

§285.61.Duties and Responsibilities of Installers.

An installer shall:

(1) possess a current Installer I or Installer II license before beginning construction of an on-site sewage facility (OSSF);

(2) record the installer's license number on all bids, proposals, contracts, invoices, proposed construction drawings, or other correspondence with owners, the executive director, or authorized agents;

(3) provide true and accurate information on any application or any other documentation;

(4) begin the construction of an OSSF only after obtaining documentation that the owner, or owner's agent, has the permitting authority's authorization to construct, unless a permit is not required;

(5) notify the permitting authority of the date on which the installer plans to begin the construction of an OSSF, unless a permit is not required;

(6) construct an OSSF to meet the minimum criteria required by this chapter or the more stringent requirements of the permitting authority;

(7) construct the OSSF that has been authorized by the permitting authority for the specific location identified in the site evaluation;

(8) stop construction and return to the permitting authority to change the planning materials for the permit if site or soil conditions, materials, or supplies make compliance with the planning materials impossible;

(9) be present at the job site during the construction of the OSSF or be represented by an apprentice;

(10) be present at the job site at least once each work day if the OSSF work is supervised by an apprentice and verify that the work performed by the apprentice is according to the requirements of this chapter;

(11) request the initial, final, and any other required inspection or inspections from the permitting authority;

(12) refrain from removing materials from, or altering components of, an OSSF after the final inspection;

(13) submit to the permitting authority, within 72 hours of starting emergency repairs, a written statement describing the need for any emergency repair and the work performed;

(14) perform maintenance, keep a maintenance record, and submit maintenance reports to the permitting authority and the owner for an OSSF for which the installer has contracted to provide maintenance or, when requested by the homeowner of an aerobic OSSF, train the owner according to §285.7 of this title (relating to Maintenance Requirements);

(15) maintain a current address and phone number with the executive director and submit any change in address or phone number in writing within 30 days after the date of the change; and

(16) when requested by the homeowner, make replacement parts available to all homeowners who have been trained to maintain their own aerobic system.

§285.64.Duties and Responsibilities of Maintenance Companies.

A maintenance company shall:

(1) possess a current registration from the executive director and a current certification from the manufacturer;

(2) employ at least one individual who is licensed as an Installer II and who is certified by the manufacturer of the on-site sewage facility (OSSF) system as qualified to provide maintenance services;

(3) ensure maintenance of accurate records of permitting, fees, inspections, and reports;

(4) satisfy the requirements of the maintenance contract between the homeowner of the OSSF system and the maintenance company according to §285.7(a) of this title (relating to Maintenance Requirements);

(5) maintain a current address and phone number with the executive director and submit any change in address or phone number to the executive director in writing within 30 days after the date of the change;

(6) perform maintenance on each OSSF system under executed contract, keep a maintenance record, and submit maintenance reports to the permitting authority and the owner of the OSSF for whom the installer has contracted to provide maintenance, according to §285.7 of this title; and

(7) provide maintenance training to any homeowner of an aerobic on-site sewage system when requested, according to §285.7 of this title.

§285.65.Suspension or Revocation of License or Registration.

(a) Suspension. In addition to the items listed in §30.33 of this title (relating to License or Registration Denial, Warning, Suspension, or Revocation), the executive director may suspend the following licenses for the following reasons.

(1) An on-site sewage facility (OSSF) installer's license can be suspended for:

(A) failing to perform required maintenance on an OSSF for at least eight consecutive months (the failure to maintain records is evidence of failure to perform maintenance on the OSSF);

(B) failing to properly submit maintenance reports required by §285.7(d) of this title (relating to Maintenance Requirements) for an individual OSSF in a 12-month period;

(C) failing to properly submit four or more required OSSF maintenance reports over any two-year period;

(D) failing to provide proper maintenance training to an owner of an aerobic OSSF when requested by the owner;

(E) failing to provide proper maintenance training to an owner of an aerobic OSSF with a commission-approved course; or

(F) failure to make replacement parts available to all homeowners who have been trained to maintain their own aerobic system.

(2) A designated representative's license can be suspended for:

(A) failing to verify, before the initial inspection for a particular OSSF, that the individual installing the OSSF is a properly licensed installer;

(B) failing to investigate nuisance complaints or complaints against installers, within 30 days of receipt of the complaint, according to §285.71 of this title (relating to Authorized Agent Enforcement of OSSFs); or

(C) failing to enforce the requirements of an order, ordinance, or resolution of an authorized agent;

(b) Revocation. In addition to the items listed in §30.33 of this title, the executive director may revoke an OSSF installer's license, a designated representative's license, a site evaluator's license, an apprentice's registration, or a maintenance company's registration for the following reasons.

(1) An OSSF installer's license can be revoked for:

(A) constructing, or otherwise facilitating the construction of, an OSSF that is not in compliance with this chapter;

(B) allowing, or beginning, the construction of an OSSF without a permit when a permit is required;

(C) failing to provide proper maintenance training to an owner of an aerobic OSSF when requested by the owner;

(D) failing to provide proper maintenance training to an owner of an aerobic OSSF in a timely manner; or

(E) failing to provide proper maintenance training to an owner of an aerobic OSSF with a commission-approved course.

(2) A designated representative's license can be revoked for:

(A) approving construction of an OSSF that is not in conformance with this chapter, the authorized agent's approved order, ordinance, or resolution or the notice of approval;

(B) practicing as an apprentice or an installer in the authorized agent's area of jurisdiction while employed, appointed, or contracted by that authorized agent; or

(C) working for a maintenance company in the authorized agent's area of jurisdiction while employed, appointed, or contracted by that authorized agent.

(3) A site evaluator's license can be revoked for failing to maintain a current Installer II license, designated representative license, professional engineer license, professional sanitarian license, or a certified professional soil scientist certificate.

(4) An apprentice's registration can be revoked for:

(A) acting as, advertising, or performing duties and responsibilities of an installer without the direct supervision of, or direct communication with, the supervising installer; or

(B) receiving compensation for an OSSF installation from someone other than the supervising installer.

(5) A maintenance company's registration can be revoked for:

(A) failing to perform required maintenance on an aerobic OSSF in a 12-month period; or

(B) failing to properly submit maintenance reports required by §285.7(d) of this title for an individual homeowner in any consecutive 12-month period.

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 July 14, 2006.

TRD-200603749

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 24, 2006

For further information, please call: (512) 239-0177

Subchapter F. LICENSING AND REGISTRATION REQUIREMENTS FOR INSTALLERS, APPRENTICES, DESIGNATED REPRESENTATIVES, AND SITE EVALUATORS

30 TAC §285.64

STATUTORY AUTHORITY

The repeal is adopted under the authority granted to the commission by the Texas Legislature in TWC, Chapter 37, and THSC, Chapter 366. The repeal is also adopted under the general authority granted in TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; TWC, §5.102, which establishes the commission's authority necessary to carry out its jurisdiction; TWC, §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; and TWC, §7.002, which authorizes the commission to enforce provisions of the TWC and the THSC.

The adopted repeal implements TWC, §37.002, which requires the commission to adopt rules to establish registration requirements for maintenance providers that will service and maintain on- site sewage disposal systems using aerobic treatment under THSC, §366.0515, and to impose administrative and criminal penalties under TWC, §§7.173 - 7.175.

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 July 14, 2006.

TRD-200603750

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 24, 2006

For further information, please call: (512) 239-0177

Subchapter G. OSSF ENFORCEMENT

30 TAC §285.70, §285.71

STATUTORY AUTHORITY

The amendments are adopted under the authority granted to the commission by the Texas Legislature in TWC, Chapter 37, and THSC, Chapter 366. The amendments are also adopted under the general authority granted in TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; TWC, §5.102, which establishes the commission's authority necessary to carry out its jurisdiction; TWC, §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; and TWC, §7.002, which authorizes the commission to enforce provisions of the TWC and the THSC.

The adopted amendments implement TWC, §37.002, which requires the commission to adopt rules to establish registration requirements for maintenance providers that will service and maintain on-site sewage disposal systems using aerobic treatment under THSC, §366.0515, and to impose administrative and criminal penalties under TWC, §§7.173 - 7.175.

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 July 14, 2006.

TRD-200603751

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 24, 2006

For further information, please call: (512) 239-0177

Subchapter I. APPENDICES

30 TAC §285.90

STATUTORY AUTHORITY

The amendment is adopted under the authority granted to the commission by the Texas Legislature in TWC, Chapter 37, and THSC, Chapter 366. The amendment is also adopted under the general authority granted in TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; TWC, §5.102, which establishes the commission's authority necessary to carry out its jurisdiction; TWC, §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; and TWC, §7.002, which authorizes the commission to enforce provisions of the TWC and the THSC.

The adopted amendment implements TWC, §37.002, which requires the commission to adopt rules to establish registration requirements for maintenance providers that will service and maintain on-site sewage disposal systems using aerobic treatment under THSC, §366.0515, and to impose administrative and criminal penalties under TWC, §§7.173 - 7.175.

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 July 14, 2006.

TRD-200603752

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 24, 2006

For further information, please call: (512) 239-0177

Chapter 311. WATERSHED PROTECTION

Subchapter H. REGULATION OF QUARRIES IN THE JOHN GRAVES SCENIC RIVERWAY

30 TAC §§311.71 - 311.82

The Texas Commission on Environmental Quality (commission) adopts new §§311.71 - 311.82. Sections 311.71, 311.72, 311.74, 311.76 - 311.78, 311.81, and 311.82 are adopted with changes to the proposed text as published in the March 24, 2006, issue of the Texas Register (31 TexReg 2411). Sections 311.73, 311.75, 311.79 and 311.80 are adopted without changes and the text will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

Senate Bill (SB) 1354, 79th Legislature, 2005, amended Texas Water Code (TWC), Chapter 26 by adding new Subchapter M, Water Quality Protection Areas; specifically §§26.551 - 26.562. The statute addresses permitting, financial responsibility, inspections, water quality sampling, enforcement, cost recovery, and interagency cooperation with regard to quarry operations. The requirements of the statute are applicable to a pilot program in the John Graves Scenic Riverway. The John Graves Scenic Riverway (JGSR) is defined as the Brazos River Basin, and its contributing watershed, located downstream of the Morris Shepard Dam on the Possum Kingdom Reservoir in Palo Pinto County, Texas, and extending to the county line between Parker and Hood Counties, Texas.

Chapter 311, Subchapter H, implements §§26.551 - 26.554 and 26.562. New Subchapter H establishes the permitting and financial assurance requirements for the John Graves Scenic Riverway pilot program. A corresponding rulemaking is published in this issue of the Texas Register that includes the addition of Subchapter W, Financial Assurance for Quarries, to 30 TAC Chapter 37, Financial Assurance.

SECTION BY SECTION DISCUSSION

Adopted new §311.71, Definitions, defines the terms used within the subchapter. Definitions for the following terms are consistent with definitions found in SB 1354: aggregates, John Graves Scenic Riverway, operator, overburden, owner, pit, quarry, quarrying, and water body. The following definitions were added to, or modified from, those contained in SB 1354: 25-year, 24-hour rainfall event, aquifer, best management practices, natural hazard lands, navigable, reclamation, restoration, responsible party, structural controls, tertiary containment, and water quality protection area. Definitions for 25-year, 24-hour rainfall event, aquifer, best management practices, natural hazard lands, structural controls, and tertiary containment are generally consistent with other federal or state rules found in 40 Code of Federal Regulations and 30 TAC, respectively.

Adopted new §311.71(7) defines navigable, for the purposes of this subchapter, as "Designated by the United States Geological Survey (USGS) as perennial on the most recent topographic map(s) published by the USGS, at a scale of 1:24,000." Providing this definition eliminates much of the potential confusion regarding the term, given the significant variability in scope of other federal and state designations of navigability. This definition establishes the scope of permitting requirements most closely related to perennial water bodies, where impacts to water quality, aquatic life, and navigability are of concern, and allows the commission to focus permitting and enforcement resources in those areas. Additionally, the use of USGS topographic maps as the source for determining navigability provides an easily accessible source and eliminates the interpretation or case-by-case legal or factual analysis necessary to the use of the established definitions intended for the purpose of delineating property ownership.

Adopted new §311.71(14) includes definitions for reclamation and restoration, respectively.

The definition of refuse is deleted from the proposed text at §311.71(15) as the term is not used within the subchapter. Subsequent definitions are renumbered accordingly.

Adopted new §311.71(15) defines responsible party as "Any owner, operator, lessor, or lessee who is primarily responsible for the overall function and operation of a quarry in the water quality protection area defined by §311.71(20)." This definition was modified from the definition found in SB 1354 so that it specifically references quarries located in a water quality protection area, as defined within the subchapter.

New §311.71(16) is adopted with changes to the proposed definition for restoration. The adopted text specifically identifies that restoration includes on- and off-site stabilization to reduce or eliminate an unauthorized discharge, or substantial threat of an unauthorized discharge from the permitted site.

Adopted new §311.71(20) defines a water quality protection area as "For the purposes of this subchapter, the Brazos River and its contributing watershed occurring in Palo Pinto and Parker Counties below the Morris Shepard Dam." SB 1354 requires the commission to designate water quality protection areas through commission rules. The definition of water quality protection area focuses permitting and enforcement resources within Palo Pinto and Parker Counties, where impacts from quarrying are of concern.

Adopted new §311.72, Applicability, identifies activities regulated by this subchapter and activities specifically excluded from regulation, consistent with SB 1354. Activities regulated by this subchapter include quarrying within a water quality protection area in the John Graves Scenic Riverway, as identified in subsection (a). Subsection (a) is adopted with changes so that it identifies the applicability of this subchapter as a pilot program with an expiration date of September 1, 2025. Activities specifically excluded from regulation are identified in subsection (b)(1) - (4). Paragraphs (1), (4), and (5) exclude, respectively, the following: the construction or operation of a municipal solid waste facility regardless of whether the facility includes a pit or quarry that is associated with past quarrying; an activity, facility, or operation regulated under Natural Resources Code, Chapter 134, Texas Surface Coal Mining and Reclamation Act; and quarries mining clay and shale for use in manufacturing structural clay products. Paragraphs (2) and (3) exclude, respectively, the following: a quarry, or associated processing plant, that on or before January 1, 1994, has been in regular operation without cessation of operation for more than 30 consecutive days and under the same ownership; and the construction or modification of associated equipment located on a quarry site or associated processing plant site identified in §311.72(b)(2). Where facilities are specifically excluded by paragraphs (2) and (3), the exclusion is applicable to operations within the current leasehold or property boundaries. Where these facilities acquire additional leaseholds or property, quarrying in those new areas will be subject to the requirements of this subchapter. Facilities subject to the exclusions provided in subsection (b)(2) and (3) are required to maintain documentation on site to demonstrate the exemption, as provided in subsection (c). Subsection (c) is adopted with changes to require all facilities subject to the exemptions within subsection (b) to maintain documentation on site to demonstrate exemptions. Subsection (c) lists the types of acceptable documentation in demonstrating exemptions. The responsible party carries the burden of proof in demonstrating that a quarry meets the exclusions listed in subsection (b).

In addition to the exclusion listed in new §311.72(b)(5), quarries mining clay and shale for use in manufacturing structural clay products are also excluded from regulation through the definition of aggregate and quarry in SB 1354 and this subchapter. This exclusion includes current operations, the expansion of current operations on current property, the expansion of current operations to adjacent properties, or new operations.

Adopted new §311.73, Prohibitions, identifies areas within a water quality protection area in the John Graves Scenic Riverway where quarrying is prohibited, consistent with SB 1354. Section 311.73(a) prohibits the construction or operation of any new quarry, or the expansion of an existing quarry, located within 200 feet of any water body, as defined by this subchapter. The construction or operation of any new quarry, or the expansion of an existing quarry, located between 200 feet and 1,500 feet of any water body is prohibited except where the requirements in §§311.75(2), 311.77, and 311.78(b) are met. For the purposes of this subchapter, a new quarry is any quarry that commenced operations after September 1, 2005. An existing quarry is any quarry that was in operation prior to September 1, 2005.

Throughout this subchapter, prohibitions, application requirements, and performance criteria are established based upon the quarry's location relative to a navigable water body (as defined in §311.71). Where location is established as the distance from a water body, the distance is measured from the gradient boundary. Federal Emergency Management Agency flood hazard maps identify the 100-year floodplain relative to a water body.

In addition to any other required permits, new §311.74, Authorization, requires all responsible parties to seek and obtain permit coverage under 30 TAC Chapters 205 or 305. Section 311.74(b)(1) identifies the requirements of this subchapter applicable to all quarries located within a water quality protection area in the John Graves Scenic Riverway. In addition to the requirements in paragraph (1), paragraph (2) requires individual permits for all quarries located within the 100-year floodplain or within one mile of a water body. The requirements of paragraph (3) are in addition to those found in paragraphs (1) and (2) for quarries located between 200 feet and 1,500 feet of a water body. These locational distinctions are consistent with SB 1354. Paragraphs (4) and (5) address facilities located within multiple applicability zones. The requirements for the more restrictive zone are applicable to the entire quarry, except where the executive director waives, modifies, or otherwise adjusts the requirements for that portion of the quarry located outside of the more restrictive applicability zone. The executive director anticipates waiving, modifying, or otherwise adjusting the requirements for that portion of the quarry located outside of the more restrictive applicability zone where a quarry can demonstrate that the portion of the facility located inside the more restrictive applicability zone will still meet all applicable performance requirements.

Adopted new §311.75, Permit Application Requirements, outlines the permit application requirements for all quarries located within a water quality protection area in the John Graves Scenic Riverway. Section 311.75(1) outlines the permit application requirements for all quarries located within a water quality protection area in the John Graves Scenic Riverway including requirements for the submission of financial assurance for restoration. Permit application requirements for quarries located between 200 feet and 1,500 feet of a water body within a water quality protection area in the John Graves Scenic Riverway are identified in paragraph (2). Paragraph (3) allows for the executive director to request any additional information necessary for the quarry to demonstrate compliance with TWC, Chapter 26, Subchapter M or this subchapter.

Adopted new §311.76, Restoration Plan, identifies the requirements for the Restoration Plan required in §311.75(1) for all quarries located within a water quality protection area in the John Graves Scenic Riverway. The Restoration Plan provides a proposed plan of action for how the responsible party will restore a water body to background conditions following an unauthorized discharge. Subsection (a)(1) and (2) outline the requirements included in the Restoration Plan enabling the executive director to evaluate the applicant's methodology for determining the physical, chemical, or biological background conditions of each of the water bodies that may be at risk as a result of an unauthorized discharge from a quarry. Since background conditions in a water body may change over time, paragraph (3) is designed to ensure that the determination of background conditions will be completed in a timely manner and reevaluated and updated periodically. Paragraph (4) allows the applicant to consider the unique characteristics of the facility, the receiving waters at risk, and the background conditions of these water bodies and requires the applicant to identify the specific goals and objectives of potential restoration actions based on site-specific qualities of the adjacent water bodies and the facility. Paragraph (5) requires the applicant to include an evaluation of a reasonable range of potential restoration alternatives that may be implemented to achieve the goals and objectives identified in the Restoration Plan to return affected water bodies to background conditions. It further requires that the applicant identify a preferred restoration alternative that would be implemented in the event of an unauthorized discharge. To ensure the effectiveness and long-term success of the restoration action, paragraph (6) requires the applicant to describe the process that will be used to monitor the effectiveness of the preferred restoration action and identify the performance criteria that will be used to determine the success of the restoration or the need for interim on- and off-site stabilization. To ensure meaningful input from stakeholders on the restoration action that is ultimately implemented to restore the affected water body, paragraph (7) requires the applicant to identify a process for public involvement in the evaluation of the restoration action(s) selected to restore the receiving water body to background conditions. Paragraph (8) requires a detailed estimate of the maximum probable costs required to complete a restoration action used to support the amount of financial assurance required by §311.81(a). Subsection (b) is adopted with changes to require certification, within the appropriate area or discipline, of the Restoration Plan, in whole or by component parts, by a licensed Texas professional engineer or a licensed Texas professional geoscientist.

Adopted new §311.77, Technical Demonstration, identifies the requirements for the Technical Demonstration required in §311.75(3) for all quarries located within 200 feet to 1,500 feet of a water body within a water quality protection area in the John Graves Scenic Riverway. Requirements for a time schedule for the proposed quarry from initiation to termination of operations, including restoration, are identified in subsection (a)(1). Subsection (a)(2) - (4) provides a description of the geology, quarrying processes, and other operations that would be found on site. Identification of the type, character, and volume of all wastewater and storm water generated at the quarry is required in paragraph (5). Paragraph (6) requires the submission of a topographic map and lists all items that must be identified on the map. Paragraph (7) defines the minimum requirements for the Surface Water Drainage and Accumulation Plan, required by SB 1354. Paragraph (7)(A) requires a description of the use and monitoring of structural controls and best management practices as identified in the Best Available Technology Evaluation. The minimum items required for identification on a topographic map are listed in subparagraph (B)(i) - (v). Paragraph (8) lists the requirements for the Best Available Technology Evaluation. Paragraph (8)(A) requires that the applicant assess the use of structural controls and best management practices. Certification by a licensed Texas professional engineer is required for the design and construction of all structural controls. Subparagraph (B) requires an evaluation of performance criteria established in §311.79 and §311.80. This evaluation should help ensure that the requirements of §311.79 and §311.80 have been reviewed and will be met by the applicant. Paragraph (9) ensures that the applicant has developed procedures and schedules for the periodic review of the Technical Demonstration for consistency with quarry operations and site conditions. Subsection (b) is adopted with changes to require certification, within the appropriate area or discipline, of the Technical Demonstration, in whole or by component parts, by a licensed Texas professional engineer or a licensed Texas professional geoscientist.

Adopted new §311.78, Reclamation Plan, identifies the requirements for the Reclamation Plan required in §311.75(3) for all quarries located within 200 feet to 1,500 feet of a water body within a water quality protection area in the John Graves Scenic Riverway. The minimum requirements of the Reclamation Plan are listed in subsection (a)(1)(A) - (C). Subparagraph (A) requires the applicant to provide a description of the proposed use of the disturbed area following reclamation. The proposed use of a reclaimed area will dictate the standards for reclamation, which subparagraph (B) requires the permittee to develop. Standards for reclamation must address removal or final stabilization of all materials, waste, structures, temporary roads/railroads, and equipment; backfilling, regrading, and recontouring; slope stabilization; and the establishment of vegetation, wildlife habitat, drainage patterns, and permanent control structures, as listed in paragraph (1)(B)(i) - (xi). Paragraph (1)(B)(viii) is adopted with changes to remove references to the creation of habitat for endangered/threatened species, as the suggestion in creating habitat for endangered/threatened species has other potential regulatory implications. A description of how reclamation will be conducted and a timetable for the completion of reclamation activities is required in the Reclamation Plan in subparagraph (C). Paragraph (2) requires a detailed estimate of the maximum probable costs required to complete reclamation. Subsection (b) is adopted with changes to require certification, within the appropriate area or discipline, of the Reclamation Plan, in whole or by component parts, by a licensed Texas professional engineer or a licensed Texas professional geoscientist.

Adopted new §311.79, Performance Criteria for Quarries Located Within a Water Quality Protection Area in the John Graves Scenic Riverway, outlines the performance criteria applicable to all quarries located within a water quality protection area in the John Graves Scenic Riverway. Section 311.79(1) establishes a 45 milligrams per liter daily average effluent limitation for total suspended solids and a pH range of 6.0 to 9.0 standard units for all discharges to waters in the state. Effluent limitations for total suspended solids are established to reduce sediment loading to receiving water bodies. A daily average concentration of 45 milligrams per liter is achievable when proper best management practices and structural controls are installed and maintained. Effluent limitations for pH are established to preclude impacts to water quality and are achievable primarily through best management practices, although structural controls or treatment may be necessary. The applicability of total suspended solids and pH effluent limitations are limited in paragraph (2) to discharges resulting from a rainfall event less than the 25-year, 24-hour rainfall event. The 25-year, 24-hour rainfall event has historically been the design standard for water quality applications. Rainfall events beyond the 25-year, 24-hour rainfall event are typically considered an "act of God." To ensure that the effluent limitations established in paragraphs (1) and (2) are monitored consistently, monitoring frequencies are specified in paragraph (3) at once per day, when discharging. This monitoring schedule provides regular monitoring of discharges, allowing the commission and quarries to monitor the effectiveness of best management practices and structural controls. Paragraph (4) outlines monitoring and reporting requirements for monitoring conducted under paragraph (3). Because paragraph (2) limits the applicability of effluent limitations under severe rainfall conditions, paragraph (5) requires that the permittee install a permanent rain gauge and keep daily records of rainfall and resulting flow.

Adopted new §311.80, Additional Performance Criteria for Quarries Located Between 200 Feet and 1,500 Feet of a Water Body Located Within a Water Quality Protection Area in the John Graves Scenic Riverway, outlines additional performance criteria applicable to all quarries located between 200 feet and 1,500 feet of a water body within a water quality protection area in the John Graves Scenic Riverway. Section 311.80(1)(A) - (F) addresses design and construction requirements for final control structures including: certification of the design and construction, availability of design and construction plans and specifications, slope restrictions, water management capabilities, stabilization, inspection, and buffers. These requirements are established to ensure proper design and construction, operation, and maintenance of structural controls. Paragraph (2) provides for the proper operation of treatment, detention, and water storage tanks and ponds by requiring a minimum of two feet of freeboard. Paragraph (3) requires a depth marker so that compliance with paragraph (2) can be verified. Impacts to historical resources are addressed in paragraph (4) by requiring compliance with 36 Code of Federal Regulations Part 800 and 9 Texas Natural Resources Code, Chapter 191. Paragraph (5) addresses impacts to federal endangered/threatened, aquatic/aquatic-dependant species/proposed species or their critical habitat. As a measure of protection for water supply wells, paragraph (6) establishes siting restrictions for all waste management units. Paragraph (7) establishes requirements for secondary and tertiary containment of chemicals and fuels to reduce the potential for leaks and spills to contaminate surface or groundwater. Tertiary containment is required where quarry operations overlay aquifer or aquifer recharge areas and sufficient confining layers do not exist to preclude contamination. Secondary containment is required in all instances. Where natural hazards, frequent flooding, or areas of unstable geology exist, paragraph (8) prohibits the location of a quarry operation.

Adopted new §311.81, Financial Responsibility for Quarries Located Within a Water Quality Protection Area in the John Graves Scenic Riverway, establishes requirements for financial assurance for restoration and reclamation as required by this subchapter.

Adopted new §311.81(a) requires that the owner or operator of a quarry located in the John Graves Scenic Riverway establish and maintain financial assurance, in an amount determined by the cost estimate within the approved Restoration Plan in §311.76(a)(8), for restoration of a water body that is affected by an unauthorized discharge. The financial assurance is intended to cover the costs of site stabilization and restoration performed by an independent contractor and include design and engineering fees, costs of repairing failed or impaired structural controls, costs of soil stabilization and erosion control measures necessary to prevent additional releases, and where practicable, removal of excess silt, sediment, rocks, and debris from the affected water body.

Adopted new §311.81(b) requires that the owner or operator of a quarry located in the John Graves Scenic Riverway establish and maintain financial assurance, in an amount determined by the cost estimate within the Reclamation Plan in §311.78(a)(2), for reclamation of the quarry. The financial assurance is intended to cover the costs of reclamation performed by an independent contractor. Costs of reclamation include design and engineering fees; removal or final stabilization of all materials, waste, structures, temporary roads/railroads, and equipment; backfilling, regrading, and recontouring; slope stabilization; and the establishment of vegetation, wildlife habitat, drainage patterns, and permanent control structures.

New §311.82, Existing Quarries, is adopted with changes. In response to public comments on the proposed rules, the commission added language to this section that addresses operational provisions and permit application deadlines for existing quarries. Subsection (a) provides for existing quarries located outside the 100-year floodplain and greater than one mile from a water body to continue operating under the terms of an existing Texas Pollutant Discharge Elimination System Permit or Texas Land Application Permit, provided that the quarry maintains compliance with that permit and submits an application for a general permit issued under Subchapter H as specified in that permit. Subsection (b) provides for existing quarries located greater than 1,500 feet from a water body to continue operating under the terms of an existing Texas Pollutant Discharge Elimination System Permit or Texas Land Application Permit, provided that the quarry maintains compliance with that permit and submits an application for an individual permit within 180 days of the effective date of the adopted rules. Subsection (c) specifies that quarries located within 200 feet to 1,500 feet of a water body may not operate until the commission issues the quarry a permit under the requirements of this subchapter and requires that these facilities submit and individual permit application within 180 days of the effective date of the adopted rules. In response to separate public comment, the text citing the expiration date of this subchapter proposed at §311.82, was moved to §311.72, Applicability.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking is not subject to §2001.0225 because, although the adopted rulemaking meets the definition of a "major environmental rule" as defined in §2001.0225, it does not meet any of the four applicability requirements listed in §2001.0225(a). Texas Government Code, §2001.0225(a), only applies to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

In this case, the adopted rules do not meet any of these four applicability requirements. First, regardless of whether the rules exceed a standard set by federal law, the adopted rules are specifically required to implement state law in SB 1354. Second, the adopted rules do not exceed a requirement of state law, in that they are being adopted to implement specific requirements of SB 1354. Third, the adopted rules do not exceed an express requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program. Fourth, the commission does not adopt these rules solely under the general powers of the agency, but rather under the authority of SB 1354, which directs the commission to implement rules under TWC, Chapter 26.

The commission solicited public comment on the draft regulatory impact analysis in the March 24, 2006, issue of the Texas Register (31 TexReg 2411). No comments were received on the draft regulatory impact analysis.

TAKINGS IMPACT ASSESSMENT

The commission evaluated these adopted rules and prepared an assessment of whether the adopted rules constitute a takings under Texas Government Code, Chapter 2007.

The specific purpose of the adopted rules is to implement SB 1354. The adopted rules protect a unique portion of the Brazos River watershed between Possum Kingdom Reservoir in Palo Pinto County and Parker County, Texas, to be known as the John Graves Scenic Riverway, from ongoing mining and quarrying activities in the proximity of the beds, bottoms, and banks of the river that significantly impair the quality of the water flowing in the river.

These adopted rules implement the requirements for quarries in the John Graves Scenic Riverway that were established in SB 1354. Under SB 1354, the commission may not authorize a quarry within 200 feet of a navigable water body within the John Graves Scenic Riverway. The bill prohibits the commission from authorizing the construction or operation of a new quarry or the expansion of an existing quarry between 200 and 1,500 feet of a navigable waterbody within the John Graves Scenic Riverway, unless certain performance criteria established by rulemaking are satisfied. SB 1354 further establishes that a quarry located or proposed to be located within one mile of a navigable waterbody in the John Graves Scenic Riverway must get an individual permit. Those quarries located or proposed to be located at a distance more than one mile must be covered under a general permit. This adopted rulemaking and related restrictions implement the express requirements of SB 1354.

Promulgation and enforcement of these adopted rules would be neither a statutory nor a constitutional taking of private real property, because although the adopted rules do affect private real property, they do not constitute a "taking" as defined by the Private Real Property Rights Preservation Act. According to the Act, "taking" means a governmental action that affects private real property, in whole or in part or temporarily or permanently, in a manner that requires the governmental entity to compensate the private real property owner as provided by the Fifth and Fourteenth Amendments to the United States Constitution or Texas Constitution, Article I, §17 or §19; or a governmental action that: 1) affects an owner's private real property that is the subject of the governmental action, in whole or in part or temporarily or permanently, in a manner that restricts or limits the owner's right to the property that would otherwise exist in the absence of the governmental action; and 2) is the producing cause of a reduction of at least 25% in the market value of the affected private real property, determined by comparing the market value of the property as if the governmental action is not in effect and the market value of the property is determined as if the governmental action is in effect.

The Fifth Amendment to the United States Constitution states in relevant part: "Nor shall private property be taken for public use, without just compensation." The takings clause applies to the states by virtue of the Fourteenth Amendment. Similarly, Texas Constitution, Article I, §17 provides: "No person's property shall be taken, damaged or destroyed without adequate compensation being made, unless by the consent of such person; and, when taken, except for the use of the State, such compensation shall be first made, or secured by a deposit of money . . .."

Texas courts have held that takings can be classified as either physical or regulatory. Physical takings occur when the government authorizes an unwarranted physical occupation of an individual's property. The adopted rules do not authorize the physical occupation of any private real property; therefore, they will not result in a physical takings of private real property. A regulatory takings occurs when a regulation does not substantially advance legitimate state interests, or when a regulation either denies a landowner all economically viable use of property, or unreasonably interferes with a landowner's right to use and enjoy that property.

The adopted rules substantially advance a legitimate state interest by implementing SB 1354, relating to the protection of water quality in watersheds threatened by quarry activities; establishing a pilot program in a certain portion of the Brazos River wastershed; and providing penalties. The commission is tasked with maintaining the quality of water in the state consistent with the public health and enjoyment, and the propagation and protection of terrestrial and aquatic life. SB 1354 is being implemented to protect the John Graves Scenic Riverway from ongoing mining and quarrying activities in the proximity of the beds, bottoms, and banks of the river that significantly impair the quality of the water flowing in the river.

Determining whether all economically viable use of a property would be denied entails an analysis of whether value remains in property subject to these rules if the rules were adopted. The adopted rules do not prohibit quarrying altogether. While the adopted rules would prohibit quarrying within 200 feet of a navigable water body within the John Graves Scenic Riverway, quarrying would be permitted between 200 feet and 1,500 feet of a water body, provided that certain performance criteria are met. Facilities located more than one mile from a water body may obtain a general permit under TWC, §26.040. In addition, the adopted rules do not restrict other potential uses of property located in the John Graves Scenic Riverway. Therefore, the adopted rules would not deny any landowner all economically viable uses of a property.

Determining whether the adopted rules would unreasonably interfere with a landowner's right to use and enjoy property would require consideration of two factors: 1) the economic impact of the regulation; and 2) the extent to which the adopted rules interfere with distinct investment-backed expectations. This determination is typically made by courts on a fact-intensive, case-by-case basis.

As previously stated, the adopted rules do not prohibit quarrying altogether; instead, the rules restrict quarrying activities that will protect the quality of the water flowing in the John Graves Scenic Riverway. The commission does not anticipate that the adopted rules will unreasonably interfere with a landowner's investment-backed expectations, nor will the adopted rules be the producing cause of a 25% reduction in the market value of affected private real property.

The commission solicited public comment on the takings impact assessment in the March 24, 2006, issue of the Texas Register (31 TexReg 2411). No comments were received on the takings impact assessment.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission reviewed the adopted rulemaking and found that the rules are neither identified in Coastal Coordination Act Implementation Rules, 31 TAC §505.11(b)(2), relating to Actions and Rules Subject to the Coastal Management Program, nor will it affect any action/authorization identified in Coastal Coordination Act Implementation Rules, 31 TAC §505.11(a)(6). Therefore, the adopted rules are not subject to the Texas Coastal Management Program.

PUBLIC COMMENT

The public comment period ended on April 24, 2006, at 5:00 p.m. A public hearing on the proposed rules was held in Mineral Wells on April 6, 2006, at 6:30 p.m. at the Mineral Wells City Hall Annex, Council Chambers, 115 Southwest First Street, Mineral Wells, Texas. Oral comments were received from the Brazos River Conservation Coalition (BRCC). Written comments were received from the BRCC; Hilgers Bell & Richards (Hilgers Bell); Jackson, Sjoberg, McCarthy & Wilson, L.L.P. (McCarthy), on behalf of multiple parties including one individual, the Rocking "W" Ranch, and the BRCC; Harris County Precinct 4 Parks (Harris County); Lloyd Gosselink Blevins Rochelle & Townsend, P.C. (Lloyd Gosselink), on behalf of Southwestern Brick Institute; GEOS Consulting (GEOS); Texas Aggregates and Concrete Association (TACA); the Texas Board of Professional Geoscientists (TBPG); Texas Industries, Inc. (TXI); Vulcan Materials Company (Vulcan); Westward Environmental, Inc. (Westward); and 430 individuals. The comments generally concerned technical issues.

RESPONSE TO COMMENTS

Definitions - Miscellaneous

TXI commented that the definition for "natural hazard lands" found at §311.71(6) should be deleted as the definition is not in SB 1354 and does not further the intent of the legislation.

TWC, §26.553(d)(1)(D) specifies that additional performance criteria established by the commission rule and incorporated into the permit address "whether operations could affect natural hazard lands . . .." These additional performance criteria are established in the proposed rules at §311.80(8). As a result, the commission finds the supporting definition of natural hazard lands at §311.71(6) necessary, and has retained that definition in the adopted rule text.

TXI commented that the definition for refuse at §311.71(15) should be deleted.

The commission agrees that the term "refuse" should be deleted as the term is not used within this subchapter. The definition has been removed from the adopted text and subsequent definitions have been renumbered accordingly.

In order to more clearly limit the definition for responsible party found at §311.71(16), TXI offered the following: "Any owner, operator, lessor, or lessee who is primarily responsible for overall function and operation of quarry located in the water quality protection area as defined in this section subject to this rule."

The commission disagrees with adding the language "subject to this rule" to the definition of responsible party. Section 311.71 states that "the following words and terms, when used in the following subchapter, have the following meanings." This language makes it clear that these definitions are for this subchapter only, so the suggested language by TXI is unnecessary.

TXI commented that the definition for structural controls at §311.71(17) should be deleted, as the term is not defined in SB 1354.

The commission disagrees with removing the definition of structural controls from the subchapter and has retained the definition in the adopted rule text. The definition of structural controls is included in the proposed rules at §311.71(17) to clarify provisions at §311.77(a)(7)(A) and (B)(iv) and (8)(A) and (C), all of which reference structural controls. The provisions proposed at §311.77(a)(7)(A) and (B)(iv) and (8)(A) and (C) are part of the Technical Demonstration that supports the commission finding that additional performance criteria will be met for those quarries authorized to operate within 200 to 1,500 feet of a water body located within a water quality protection area in the John Graves Scenic Riverway.

Definitions - Navigable and Waterbody

The BRCC and McCarthy commented on the proposed definition of navigable at §311.71(7) and the subsequent definition of water body at §311.71(19). The BRCC and McCarthy stated that the proposed definition of navigable is inconsistent with, and a more narrow interpretation of, navigable at law than that found at Texas Natural Resource Code, §21.003(3). Additionally, the BRCC and McCarthy asserted that the definition of navigable, as proposed, does not conform with a "navigable in fact" interpretation of navigability either. BRCC and McCarthy noted the potential for intermittent streams to impact downstream perennial streams and stated that the proposed definition of navigable fails to regulate such intermittent streams. Specifically, the BRCC noted that Grindstone Creek, Turkey Creek, and Rock Creek do not appear to be included within the definitions of navigable and water body.

Westward suggested that the commission designate affected water bodies rather than relying upon the definition of navigable. TXI suggested the following definition for water body: "the area defined by the river and its next order contributing drainage area."

The objective in establishing a definition of a navigable water body within the John Graves Scenic Riverway was to define the regulatory requirements of SB 1354 in a way that was predictable and readily understandable, by the commission, consultants, applicants, and the public. The commission agrees that the proposed definition of "navigable," and the related term of "water body," are not the same as the definition of "navigable stream" under Texas Natural Resources Code, §21.001(3). In Texas, a stream is navigable if it is navigable in fact or navigable by law. The existing definition under the Natural Resources Code exists for the purpose of determining land ownership and the separation of the public domain from private property and does not have a specific basis in hydrology. The commission recognizes the potential benefit in establishing the scope of the rules consistent with the definition of public land and the public domain of streams that are either navigable in fact or navigable by law. However, using the statutory definition in the Natural Resources Code, as opposed to the definition in this subchapter, is a less practical solution to effectively administer the regulatory program authorized under SB 1354.

While current law provides an existing definition of navigability in a different context, applying that definition to this subchapter raises some concerns because questions of law and fact can lead to uncertainty in the administration of these regulations. Ultimately, the question of whether a stream is navigable under the existing statutory definition in the Texas Natural Resources Code, as recommended in the comments, creates an issue that would need to be determined on a case-by-case basis and potentially require resolution in court, if disputed. It is that uncertainty, and the desire to be able to clearly apply this subchapter, that prompted the commission to propose the use of the USGS designation of perennial streams as a basis for determination.

The commission disagrees with the representation that the definition of navigability within this subchapter will result in some stream segments going unregulated or that the definition will not allow the regulation of quarries or intermittent streams. Under SB 1354 and this subchapter, all quarries and all streams within the designated water quality protection area not expressly exempted by law will be subject to regulation and permitting. Facilities located adjacent to water courses that are non-navigable will be required to obtain authorization under a general permit. The general permit will include performance criteria and require restoration plans and financial assurance. The performance criteria established by this subchapter are intended to control discharges from quarries located anywhere within the designated water quality protection area, including those located, or to be located, adjacent to intermittent streams.

The commission notes that some water courses may not have been accurately represented in maps that were displayed at public hearings on the proposed rules and prepared to show the extent of the water quality protection area. Of the streams specifically referenced by the comments, Grindstone Creek may contain reaches designated as perennial and defined as a water body under this subchapter. The maps were intended to be a general description of the designated water quality protection area and not an official map. It is the responsibility of an applicant to demonstrate compliance with any requirements that are based on designation of a water body under this subchapter.

No changes to the rules, as proposed, are made in response to these comments. Likewise, no changes are made in response to recommendations that the commission designate affected water bodies rather than rely on a definition of navigability or water bodies be defined as the Brazos River and the next order of streams in the contributing drainage area. Either approach to designating water bodies without some technical or factual basis and without further statutory guidance is inconsistent with the authority provided in SB 1354 and arbitrary.

Applicability

TACA and Lloyd Gosselink requested that the proposed rules identify the subchapter as applying to a pilot program regulating quarrying within a water quality protection area in the John Graves Scenic Riverway. Lloyd Gosselink specifically requests that this text be added at §311.72(a).

The commission has modified the text at §311.72(a) to read: "This subchapter applies to a pilot program regulating quarrying within the water quality protection area designated by this subchapter, in the John Graves Scenic Riverway. This subchapter expires on September 1, 2025." This modification does not effect a change in the applicability or expiration of this subchapter, but clarifies the application of these rules as a pilot program expiring September 1, 2025, consistent with TWC, §26.552.

The BRCC and McCarthy requested that quarries excluded from regulation under Subchapter H, at §311.72(b)(1), (4), and (5) maintain documentation onsite of their exemption.

The commission agrees with this comment and has revised §311.72(c) to require facilities subject to the exclusions under §311.72(b)(1), (4), and (5) to maintain documentation onsite of their exemption. This documentation includes, but is not limited to: any permit issued by the commission, Railroad Commission of Texas, or the United States Environmental Protection Agency.

TACA commented that the term "cessation of operation," as used at §311.72(b)(2) and (c)(2) be clarified to mean "cessation of production, sales, or operations altogether for a period of 30 days or more."

The commission declines to expand upon "cessation of operation." TWC, §26.552(c)(1) states this subchapter does not apply to a quarry or associated processing plant that since or before January 1, 1994, has been in regular operation in the John Graves Scenic Riverway without cessation of operation for more than 30 consecutive days and under the same ownership. TWC, §26.552(c)(1) provides sufficient clarity. The commission chooses to follow the explicit language of the TWC and not expand on the term "cessation of operation."

TXI requested that §311.72(b)(2) be revised to read as follows: "A quarry, its owned or leased land, or associated processing plant, that since on or before January 1, 1994, has been in regular operation without cessation of operation for more than 30 consecutive days and under the same ownership or control." TXI further requested that §311.72(c)(1) be revised to read as follows: "Documentation demonstrating ownership control includes, but is not limited to: deeds, property tax receipts, leases, or insurance records."

The commission declines to add the word "control" to the text in §311.72(b)(2) and (c)(1). TWC, §26.552(c)(1) states this subchapter does not apply to a quarry or associated processing plant that since or before January 1, 1994, has been in regular operation in the John Graves Scenic Riverway without cessation of operation for more than 30 consecutive days and under the same ownership. Section 26.552(c)(1) makes no mention of control, but says ownership. Also, the definition of owner in §26.551(5) does not mention control. Since neither the definition of owner nor the exclusion mention "control," the commission declines to add it to §311.72(b)(2) and (c)(1).

Westward commented that the exclusions available at §311.72(b)(2) and (3) should apply to additional leases or property further from the river than existing operations as they have a lower potential to impact the Brazos River.

Any expansion of an existing quarry located within a water quality protection area in the John Graves Scenic Riverway beyond current leaseholds or property boundaries will require a permit under this subchapter. The commission disagrees that the exclusions at §311.72(b)(2) and (3) should apply to subsequent leaseholds or properties. The commission limited these exclusions to current leaseholds/property boundaries, consistent with the commission's understanding of legislative intent.

Westward commented that the requirement for demonstrating continuous operation without cessation of operation for more than 30 consecutive days beginning on or before January 1, 1994, at §311.72(b)(2) is excessive.

The commission recognizes that §311.72(b)(2) requires excluded facilities to document continuous ownership over an extended period of time. However, this documentation is necessary to prove a readily available, definitive interpretation on the applicability of this subchapter.

Westward commented that financial assurance should not be required for small operations that mine on private property for the landowner, where the property itself is not within the distance limits of this bill but are in the listed counties; specifically, those that do not affect the John Graves Scenic Riverway.

The commission disagrees with this comment. If a quarry is located in the water quality protection area defined in §311.71, then that quarry will have to maintain financial assurance if the quarry is producing aggregates for commercial sale. The type of financial assurance required depends on the location of the quarry in relation to a designated water body.

Prohibitions

The BRCC comments on the expansion of existing quarries, as discussed in §311.73. Specifically, the BRCC has questioned the preamble discussion regarding expansion, and whether defining expansion as "any change to an existing quarry that results in additional disturbance" is appropriate.

The commission disagrees with this comment. The language regarding an additional disturbance does not appear within the rule itself but in the preamble's SECTION BY SECTION DISCUSSION. It is the commission's understanding that SB 1354 precluded quarry operations within 200 feet of a water body. Any operations at an existing quarry will result in an additional disturbance; therefore, existing quarries may not continue to operate within 200 feet.

Authorization

TXI suggested the following text at §311.74(a): "Any responsible party shall obtain a permit subject to the requirements of Chapters 205 and 305 of this title, if applicable."

The commission designated the applicability of the subchapter at §311.72 and has, therefore, determined the addition of "if applicable" at §311.74(a) is not necessary.

TXI noted that the provision at §311.74(b)(2), relating to the application requirements for quarries located within a water quality protection area in the John Graves Scenic Riverway, has potential adverse effects on future aggregate operators outside the John Graves Scenic Riverway.

The commission disagrees with this comment. The provision found at §311.74(b)(2) specifically states that these requirements are "for discharges from quarries located within a water quality protection area in the John Graves Scenic Riverway." As written, the provision clearly limits that applicability of this subchapter and will not apply to other facilities or quarries located outside a water quality protection area in the John Graves Scenic Riverway.

Vulcan commented on the requirements for quarries located within multiple applicability zones found at §311.74(b)(4) and (5). Specifically, Vulcan suggested that the commission develop specific criteria for waiving, modifying, or otherwise adjusting the requirements for that portion of the quarry outside the more restrictive applicability zone.

The commission anticipates waiving, modifying, or otherwise adjusting the requirements for that portion of the quarry outside the more restrictive applicability zone where a quarry can demonstrate that the portion of the facility located inside the more restrictive applicability zone will still meet all applicable performance requirements under this subchapter. Action by the commission in this regard will be on a case-by-case basis and determined by site-specific factors. As such, the commission may not anticipate all circumstances under which such action would or would not be appropriate, and declines to do so by establishing criteria.

Restoration and the Restoration Plan

Westward commented that there should not be public involvement in the restoration process as it is detrimental to restoration projects.

The commission has provided for public involvement in the restoration process at §311.76(a)(7) as a way to access the historical knowledge of the local public and ensure transparency of the restoration process to the general public. For these reasons, the commission has retained the text at §311.76(a)(7) without changes at adoption.

The BRCC and McCarthy commented that the definition of restoration at §311.71(16) does not clearly include restoration of the quarried or excavated area, but focuses on the receiving water body. The BRCC and McCarthy proposed the following definition for restoration: "Those actions necessary to change the physical, chemical, or biological qualities of a receiving water body in order to return the water body to its background condition. Restoration includes on- and off-site stabilization to reduce or eliminate an unauthorized discharge, or substantial threat of an unauthorized discharge, from the permitted site."

The commission agrees that modifying the definition of restoration to include "from the permitted site" at the end of the last sentence improves the rule. The commission has made this change at adoption by adding "from the permitted site" at the end of the last sentence at §311.71(16).

TXI commented that the last sentence in the definition of restoration at §311.71(16) is too broad and should be deleted.

The definition of restoration has been modified at adoption, as discussed previously, to read: "Those actions necessary to change the physical, chemical, an/or biological qualities of a receiving water body in order to return the water body to its background condition. Restoration includes on- and off- site stabilization to reduce or eliminate an unauthorized discharge, or substantial threat of an unauthorized discharge, from the permitted site." This definition specifically identifies those items considered within the context of restoration within the subchapter, while still allowing consideration of site-specific factors. The commission declines to further modify or delete this definition.

TXI commented that the requirements for a Restoration Plan found at §311.75(1)(A) and §311.76 are overly prescriptive and inconsistent with legislative intent.

TWC, §26.553(f)(1) requires a responsible party for a quarry located in a water quality protection area to submit a permit application including: "a proposed plan of action for how the responsible party will restore the receiving water body to background condition in the event of an unauthorized discharge that affects the water body . . .." The commission maintains that the provisions of the Restoration Plan found at §311.75(1)(A) and §311.76 are consistent with legislative intent in listing the minimum components of the Restoration Plan.

Westward commented that approval of the Restoration Plan by the commission should not be required. The commission should only require submission and implementation of the Restoration Plan.

The commission disagrees with this comment. TWC, §26.553(f) requires a quarry to submit a Restoration Plan and provide financial assurance for restoration. The commission has determined that approval of the Restoration Plan is necessary in determining that the Restoration Plan meets the minimum requirements listed at §311.76 and in determining that the quarry has provided the appropriate amount of financial assurance for restoration.

Technical Demonstration

TXI commented that the requirements for a Technical Demonstration at §311.75(2)(A) and §311.77 are overly prescriptive and inconsistent with legislative intent.

The commission disagrees with this comment. TWC, §26.553 prohibits the construction or operation of any new quarry, or the expansion of an existing quarry, located within 1,500 feet of a water body located within a water quality protection area. The statute then creates an exception to this prohibition for quarries located 200 feet and 1,500 feet away, subject to the commission finding that additional performance criteria are met. In order to determine that the applicant has implemented the proper structural controls and best management practices necessary to reasonably meet the additional performance criteria, the commission established additional application requirements in the Technical Demonstration. The Technical Demonstration incorporates a plan for surface water drainage and water accumulation and a best available technology evaluation required by the statute at TWC, §26.553(d)(2) and (3). As the TWC requires a finding that will be supported by the Technical Demonstration, the commission maintains that the requirements at §311.77 are minimally prescriptive and consistent with legislative intent.

TXI commented that the Best Available Technology Demonstration at §311.77(a)(8) is inconsistent with legislative intent.

The commission disagrees with this comment. TWC, §26.553 provides an exclusion to the operational prohibition for quarries located within 200 feet to 1,500 feet of a water body located within a water quality protection area, subject to the commission finding that the quarry has provided "evidence that, to the extent possible, quarrying will be conducted using the best available technology to . . ." {TWC, §26.553(d)(4)}. The Best Available Technology Demonstration provides a review of existing technologies and selection of the best available technology, consistent with TWC, §26.553(d)(4).

TXI recommends that the requirements found in the Technical Demonstration at §311.77(a)(2) - (5) require general rather than specific descriptions of the type of quarrying, material deposit, other operations, and wastewater.

The commission determined it necessary to provide detailed descriptions of the type of quarrying, material deposit, other operations, and wastewater for the commission to find that the quarry will meet additional performance criteria established at §311.80 and issue a permit for a quarry to operate within 200 to 1,500 feet of a water body. The adopted text retains the requirement for specific descriptions of the type of quarrying, material deposit, other operations, and wastewater.

TXI states that information regarding the material deposit, required at §311.77(a)(3), including the type, geographical extent, depth, and volume in addition to a description of the general area geology is proprietary information and should be struck from the rule.

The commission disagrees with this comment and the text remains at adoption. The information required at §311.77(a)(3) can be found within publically available literature and, as such, is not proprietary in nature.

TXI commented that the Surface Water Drainage and Water Accumulation Plan found at §311.77(a)(7) is overly prescriptive for quarries and adds cost for minimum benefit.

TWC, §26.553 provides an exclusion to the operational prohibition for quarries located within 200 feet to 1,500 feet of a water body located within a water quality protection area, subject to the commission finding that the quarry has "provided a plan for the control of surface water drainage and water accumulation. . ." {TWC, §26.553(d)(2)}. Consistent with the intent of controlling surface water drainage and water accumulation, the provisions at §311.77(a)(7) require the quarry to identify the structural controls and best management practices designed to control surface water drainage and water accumulation and identify on a topographic map those structural controls and best management practices. Additionally, the topographic map must identify physical features that influence storm water. The commission determined these to be the minimum requirements necessary for the commission to find that the quarry has provided an adequate plan for the control of surface water drainage and water accumulation and issue a permit for a quarry to operate within 200 feet to 1,500 feet of a water body located within a water quality protection area in the John Graves Scenic Riverway.

Reclamation and the Reclamation Plan

TXI offered the following definition for reclamation at §311.71(14): "The land treatment processes using best management practices to minimize degradation of water quality and return the land to a beneficial use."

The definition for reclamation proposed by TXI does not identify the components of reclamation incorporated into the Reclamation Plan. The definition for reclamation proposed by the commission is retained at adoption, without changes, as it is a better representation of reclamation as characterized in this subchapter.

TXI comments that the definition of reclamation found at §311.71(14) and requirements for, and specific provisions of, the Reclamation Plan found at §311.78(a)(1)(B)(i) and (a)(2) are inconsistent with the legislative intent of SB 1354. Westward states that the commission should require submission and implementation of the Reclamation Plan only, as opposed to requiring approval by the commission.

The commission disagrees with this comment. TWC, §26.553 provides an exclusion to the operational prohibition for quarries located within 200 feet to 1,500 feet of a water body located within a water quality protection area, subject to the commission finding that the quarry will meet additional performance criteria established by commission rule that address: "a plan for reclamation of the quarry that is consistent with best management standards and adopted by the commission for quarry reclamation, which may include backfilling, soil stabilization, and compacting, grading erosion control measures, and appropriate revegetation" {TWC, §26.553(d)(3)}. The definition for reclamation, application requirements for submitting a Reclamation Plan, and specific provisions within the Reclamation Plan are included so that the commission is able to make a finding as required by TWC, §26.553(d)(3). In making a finding as required by TWC, §26.553(d)(3), the commission will be providing approval of the Reclamation Plan.

TXI commented that the definition of reclamation at §311.71(14), the requirements for submitting a Reclamation Plan at §311.78(a)(1)(A), and the specific provisions of the Reclamation Plan at §311.78(a)(1)(B)(iii) - (ix) are restrictive of landowners' rights.

The commission disagrees with this comment and the provisions at §311.71(14), and §311.78(a)(1)(A) and (B)(iii) - (ix) are retained without changes in the adopted text. The Reclamation Plan requires a quarry to establish procedures and standards for reclamation based upon the final use of the quarried area. The commission purposefully constructed the Reclamation Plan in such a way as to allow the quarry to designate the final land use and the procedures and standards necessary to achieve that land use. In doing so, the commission intended to provide for a multitude of acceptable final land uses and preserving the rights of private landowners in establishing that final land use.

Vulcan commented on the requirement within the Reclamation Plan at §311.78(a)(1)(B)(viii) for the establishment of wildlife habitat, giving consideration to creation/expansion of habitat for endangered and threatened species, where applicable. Specifically, Vulcan states that SB 1354 provides protection for endangered species from expansion, but does not refer to creating habitat. Vulcan recommends that regulation of endangered and threatened species be limited to current regulations.

The commission intended to encourage, not mandate, the creation or expansion of habitat for endangered/threatened species, where appropriate. After reviewing this comment, the commission acknowledges that the reference to endangered species within this context could have other unintended regulatory implications and, as a result, has removed the reference to the creation of endangered/threatened species habitat in the adopted rules.

Performance Criteria

TXI comments that the provisions established as performance criteria at §311.79 should be covered under Chapters 205 and 305 and under a general permit for aggregate facilities.

Chapters 205 and 305 contain effluent limitations and other permit requirements applicable to discharges into and adjacent to waters in the state. The performance criteria established at §311.79 are a more specific application of effluent limits and permit requirements designed to address the potential impacts of discharges to waters into and adjacent to waters in the state from quarries located within a water quality protection area in the John Graves Scenic Riverway. The commission disagrees that the requirements at §311.79 are addressed under Chapters 205 and 305 and has retained §311.79 without changes at adoption.

In accordance with the requirements at TWC, §26.553(b), the commission is developing a general permit that will provide authorization under this subchapter to quarries located outside the 100-year floodplain and greater than one mile from a water body located within a water quality protection area in the John Graves Scenic Riverway. This general permit will incorporate the performance criteria established at §311.79, in addition to any effluent limitations and permit requirements established by another chapter within this title. Quarries within the 100-year floodplain or one mile of a water body will be regulated under an individual permit, consistent with TWC, §26.553(a).

TXI recommended that the monitoring frequencies established for flow, total suspended solids, and pH at §311.79(3) should be once per month, when discharging.

The commission disagrees with this comment. Once per day, when discharging, monitoring frequencies for flow, total suspended solids, and pH is retained in the rule at adoption. Monitoring frequencies for flow and pH are established consistent with 30 TAC §319.9(b). Concerns regarding erosion and sedimentation in the John Graves Scenic Riverway prompted the passage of SB 1354. Total suspended solids is the primary parameter of concern in the discharge from quarries; therefore, the commission established once per day, when discharging, monitoring of this parameter as opposed to once per week as listed at §319.9(b).

Additional Performance Criteria

TXI commented that quarry operators should determine the best way to protect water quality, consistent with legislative intent. The performance criteria established for protecting water quality should identify goals as opposed to the prescriptive requirements found at §311.80. TXI further states that enforcement should be based on failure to meet those goals.

TWC, §26.553 provides an exclusion to the operational prohibition for quarries located within 200 feet to 1,500 feet of a water body located within a water quality protection area, subject to the commission finding that additional performance criteria, as established by commission rule, are met. The commission has established additional performance criteria at §311.80, providing the commission authority to issue permits for quarries within 200 feet to 1,500 feet from a water body, consistent with the requirements of TWC, §26.553 and legislative intent. Although the subchapter defines additional performance criteria, §311.77(a)(8) provides for quarries to determine those structural controls and best management practices that constitute best available technology for their facility and achieve the specific performance criteria at §311.80.

TXI recommends that the final control structure side slopes must not exceed a gradient of 3:1, rather than the 1:3 proposed in the rules at §311.80(1)(B).

The commission disagrees with this comment. The commission has established this additional performance criterion at §311.80(1)(B) which stipulate that final control structure side slopes must not exceed a gradient of 1:3 (vertical:horizontal) or 33%. This criterion is consistent with the design criteria established at 30 TAC §317.4 for embankment walls on wastewater stabilization ponds.

Vulcan commented on the requirement for two feet of freeboard for all treatment, detention, and water storage tanks and ponds found at §311.80(2). Vulcan stated that the commission should clarify that the provision applies to sources that are utilized as control structures and not to water sources in place to support the operations of the quarry.

The requirement for two feet of freeboard for treatment, detention, and water storage tanks and ponds at §311.80(2) is incorporated into the rules to address the potential for overflows from these structures that would impact receiving waters. This provision was incorporated into the proposed rules to preclude overflows from treatment and detention structures containing sediment loadings that would impact receiving waters. Additionally, water storage structures are also included to preclude overflows from water storage structures due to the potential for overflows from these structures, and treatment and detention structures, to impact receiving waters through erosion as these overflows acquire sediment loadings prior to discharge into a receiving water. For this reason, the commission has retained the requirement found at §311.80(2) at adoption, that requires two feet of freeboard for all treatment, detention, and water storage tanks and ponds.

TXI and Vulcan have commented on the requirements for tertiary containment. TXI and Vulcan stated that requirements at §311.80(7) for tertiary containment go beyond federal regulations for spill control. TXI asserted that the protection of aquifers was not directed by SB 1354 and is inconsistent with the legislative intent. TXI requested that definitions for aquifer at §311.71(3) and tertiary containment at §311.71(18) be deleted from the proposed rules. Vulcan states that SB 1354 was intended to be a pilot program for protecting the John Graves Scenic Riverway from erosion and sediment deposition; and, as such, Vulcan asserted that requirements for tertiary containment found at §311.80(7) are not applicable.

The commission disagrees with the comment. Prior to SB 1354, quarries located within a water quality protection area in the John Graves Scenic Riverway were subject to the minimum federal requirements for spill control. TWC, §26.553 provides an exclusion to the operational prohibition for quarries located within 200 feet to 1,500 feet of a water body located within a water quality protection area, subject to the commission finding that additional performance criteria, as established by commission rule, are met. Specifically, TWC, §26.553(d)(1)(C) specifies that additional performance criteria established by the commission rule and incorporated into the permit address: "whether operations could affect renewable resource lands, including aquifers and aquifer recharge areas . . .." Section 311.80(7), with supporting definitions at §311.71(3) and §311.71(18) establishes tertiary containment as that performance criteria. Given the aforementioned, the commission has appropriately established more restrictive requirements (i.e., tertiary containment) for spill control for quarries operating under this exclusion.

Existing Quarries

TACA commented on the lack of specific language relating to the period of time between the effective date of the adopted rules and the amount of time required to submit, process, and issue a wastewater permit under the adopted rules. TACA stated concerns regarding quarries that are currently in compliance with Texas Pollutant Discharge Elimination System Permits that would have to cease operations until a permit is issued under the adopted rules. TACA suggested that existing quarries that have maintained authorization under a Texas Pollutant Discharge Elimination System Permit, and maintained compliance with that permit, should be allowed to remain in operation until a permit under the proposed rules is issued. TACA further stated that the commission should develop a general wastewater permit to authorize wastewater discharges, rather than require an individual permit.

The commission agrees with this comment and has added text at §311.82 to address existing quarries. In accordance with the requirements at TWC, §26.553(b), the commission is developing a general permit that will provide authorization under this subchapter to quarries located outside the 100-year floodplain and greater than one mile from a water body located within a water quality protection area in the John Graves Scenic Riverway.

Professional Certification

GEOS, one individual, TBPG, and TXI have commented on the professional certification requirements for the Restoration Plan, Technical Demonstration, and Reclamation Plan. TBPG recommended changes to the rule text that would allow a licensed Texas professional geoscientist to certify those aspects of the Restoration Plan, Technical Demonstration, and Reclamation Plan that are geoscience in nature. GEOS stated and provided supporting examples that many of the components of the Restoration Plan, Technical Demonstration, and Reclamation Plan require the expertise of a geoscientist or other professional. GEOS commented that those aspects of the Restoration Plan, Technical Demonstration, and Reclamation Plan should be completed under the responsible charge of and certified by a licensed Texas professional geoscientist. One individual stated that the components of the Restoration Plan, Technical Demonstration, and Reclamation Plan require the expertise of geologists and soil scientists, both of which are licensed in the State of Texas, and should provide for those professionals to certify appropriate components of the Restoration Plan, Technical Demonstration, and Reclamation Plan. TXI comments on the lack of necessity for the certification of the Technical Demonstration or Reclamation Plan by a licensed Texas professional engineer.

The commission revised the rule text and allows, within the appropriate area or discipline, for certification of the Restoration Plan, Technical Demonstration, and Reclamation Plan by a licensed Texas professional engineer or a licensed Texas professional geoscientist. Component parts of the Restoration Plan, Technical Demonstration, and Reclamation Plan may be independently certified by these professionals.

Investigations, Compliance, and Enforcement

The BRCC commented that twice annual inspection of the John Graves Scenic Riverway is insufficient for adequate oversight and that the success of the 20-year pilot project on the John Graves Scenic Riverway will be dictated by the effectiveness of inspection and enforcement actions.

The commission agrees that inspection and enforcement activities will play an important role in the success of the 20-year pilot project on the John Graves Scenic Riverway. The statutory requirement to inspect the John Graves Scenic Riverway twice a year both by the air and boat is in addition to existing storm water requirements and any other investigation programs that the commission administers. The commission has the ability to focus resources to address problems that may develop along the John Graves Scenic Riverway. The ability to focus agency resources was clearly demonstrated during the 2004 quarry initiative where investigations were conducted at over 300 mining operations in a month, resulting in 127 Notices of Violation, 38 Notices of Enforcement, and six referrals to the Texas Office of the Attorney General. The commission has staff in the Dallas-Fort Worth Office that will be conducting routine inspections, as necessary, at quarries. Dallas-Fort Worth Office staff are also able to respond to complaints. The commission maintains that the mandatory inspections, coupled with our ability to respond to complaints in a timely manner and focus resources as necessary, will be sufficient to detect any developing problems along the John Graves Scenic Riverway.

The BRCC noted that compliance with the new rules for small or micro-businesses will be limited at best.

The commission recognizes that many of the quarries within a water quality protection area in the John Graves Scenic Riverway are small or micro-businesses. The majority of these quarries currently maintain authorization to discharge under the multi-sector industrial storm water permit (MSGP). Under the MSGP, quarries are required to develop a storm water pollution prevention plan and utilize best management practices. The proposed rules establish additional requirements for quarries in the John Graves Scenic Riverway which build upon the MSGP requirements. In order to continue operating, these quarries will have to seek and obtain authorization under the adopted rules. The commission is conducting outreach within the John Graves Scenic Riverway and developing guidance regarding the Restoration Plan, Technical Demonstration, and Reclamation Plan in an effort to assist quarries in complying with the adopted rules. The commission will also continue to inspect and respond to complaints regarding quarries to ensure compliance.

The BRCC stated that enforcement of the proposed regulations will be extremely difficult.

The TCEQ disagrees with this comment. The proposed rules have several requirements that will aid TCEQ inspectors in determining compliance with the adopted rules such as: maintenance of depth markers and rain gauges, operating distance requirements, and recordkeeping requirements.

Fiscal Impacts and Funding

The BRCC and Vulcan have commented on the financial assessment of the proposed rules. Specifically, the BRCC and Vulcan question how these proposed rules will have no significant fiscal implications for the commission or other state and local governmental entities.

The commission reviews, primarily, those fiscal implications realized in the implementation and ongoing management of adopted rules for the commission and other state and local governmental entities. The commission is the primary governmental entity charged with the implementation and management of programs associated with the adopted rules. In reviewing the fiscal implications for the commission, the resources committed through the 2004 quarry initiative and SB 1354 rulemaking efforts were considered. The allocation of these resources was realized through prioritizing activities associated with the 2004 quarry initiative and SB 1354 rulemaking efforts. The effectiveness of this prioritization was realized in the 2004 quarry initiative, which produced 127 Notices of Violation, 38 Notices of Enforcement, and six referrals to the Texas Office of the Attorney General from investigations at over 300 mining operations conducted within a month. Based on this demonstrated ability to dedicate resources through prioritization, the commission determined that there were no significant fiscal implications.

The BRCC commented on the lack of additional funding provided for implementing the proposed rules. The BRCC recommended changes to wastewater permitting fees to specifically provide funding for the implementation and enforcement of these rules. Additionally, the BRCC recommended that all wastewater permits be renewed annually, with fees assessed likewise.

The commission currently assesses an annual Consolidated Water Quality Fee for all wastewater permits. The Consolidated Water Quality Fee is determined based upon the type of permit, permitted flow, potential toxicity, and other factors. Consolidated Water Quality Fees range from a minimum of $100 to a maximum of $75,000. The commission is currently evaluating the Consolidated Water Quality Fee structure to determine adequacy in the support of water quality monitoring, permitting, inspection, enforcement, and other commission activities. Wastewater permits subject to the adopted rules may be considered for increased fees due to the additional permit application review involved with the Restoration Plan, Technical Demonstration, and Reclamation Plan. The commission renews Texas Pollutant Discharge Elimination System Permits at a maximum of every five years in accordance with §305.71, and Texas Land Application Permits at a maximum of every ten years.

Miscellaneous

Four hundred twenty-nine individuals commented that sand mining is not regulated in Texas, specifically expressing concerns over the impact of sand mining on the San Jacinto River. These individuals state that establishing this pilot program within a water quality protection area in the John Graves Scenic Riverway is a step towards protecting all Texas rivers, including the San Jacinto River, from the effects of sand mining.

The proposed subchapter implements TWC, §26.552. This statute expressly limits its application to the John Graves Scenic Riverway. The commission appreciates this comment, but the provisions of the subchapter are not applicable to the San Jacinto River, and the comment is outside the scope of this rulemaking.

Harris County commented that regulations exist to prevent erosion and storm water runoff that are not enforced and noted specific impacts from these violations on the San Jacinto River.

The proposed subchapter implements TWC, §26.552. This statute expressly limits its application to the John Graves Scenic Riverway. The commission appreciates this comment, but the provisions of the subchapter are not applicable to the San Jacinto River, and the comment is outside the scope of this rulemaking.

Four hundred twenty-nine individuals stated general support for the proposed rules. Hilgers Bell stated support for the discussion within the preamble regarding expansions of facilities excluded from this subchapter at §311.72(b)(2) and (3). Lloyd Gosselink stated general support for the proposed rules, citing consistency with the language of the statute and legislative intent. Lloyd Gosselink also stated support for the definitions of quarry and aggregate, §311.72(b)(2) and (5), and preamble discussion regarding the exclusion for quarries mining clay and shale for use in manufacturing structural clay products. TXI stated support for the inclusion of the definition of 25-year, 24-hour rainfall event at §311.71(1).

The commission acknowledges these comments in support of the rules.

STATUTORY AUTHORITY

The new rules are adopted under TWC, §5.013, which establishes the general jurisdiction of the commission over other areas of responsibility as assigned to the commission under the TWC and other laws of the state; §5.102, which establishes the commission's general authority necessary to carry out its jurisdiction; §5.103 and §5.105, which authorize the commission to adopt rules and policies necessary to carry out its responsibilities and duties under TWC, §5.013; §5.120, which states the commission shall administer the law so as to promote the judicious use and maximum conservation and protection of the quality of the environment and the natural resources of the state; §26.011, which provides the commission with authority to adopt any rules necessary to carry out its powers, duties, and policies and to protect water quality in the state; and §26.027, which authorizes the commission to issue permits and amendments to permits for the discharge of waste or pollutants into or adjacent to water in the state. Rulemaking authority is expressly granted to the commission to adopt rules under TWC, Chapter 26 as amended by SB 1354, §2.

The adopted new rules implement SB 1354, which creates TWC, Chapter 26, new Subchapter M. SB 1354, §2, expressly requires the commission to adopt rules adequate to protect the water resources in a water quality protection area for inclusion in any authorization, including an individual or general permit.

§311.71.Definitions.

The following words and terms, when used in the subchapter, have the following meanings.

(1) 25-year, 24-hour rainfall event--The maximum rainfall event with a probable recurrence interval of once in 25 years, with a duration of 24 hours, as defined by the National Weather Service and Technical Paper Number 40, "Rainfall Frequency Atlas of the U.S.," May 1961, and subsequent amendments; or equivalent regional or state rainfall information.

(2) Aggregates--Any commonly recognized construction material originating from a quarry or pit by the disturbance of the surface, including dirt, soil, rock asphalt, granite, gravel, gypsum, marble, sand, stone, caliche, limestone, dolomite, rock, riprap, or other nonmineral substance. The term does not include clay or shale mined for use in manufacturing structural clay products.

(3) Aquifer--A saturated permeable geologic unit that can transmit, store, and yield to a well, the quality and quantities of groundwater sufficient to provide for a beneficial use. An aquifer can be composed of unconsolidated sands and gravels; permeable sedimentary rocks, such as sandstones and limestones; and/or heavily fractured volcanic and crystalline rocks. Groundwater within an aquifer can be confined, unconfined, or perched.

(4) Best management practices--Any prohibition, management practice, maintenance procedure, or schedule of activity designed to prevent or reduce the pollution of water in the state. Best management practices include treatment, specified operating procedures, and practices to control site runoff, spillage or leaks, sludge or waste disposal, or drainage from raw material storage areas.

(5) John Graves Scenic Riverway--That portion of the Brazos River Basin and its contributing watershed, located downstream of the Morris Shepard Dam on the Possum Kingdom Reservoir in Palo Pinto County, Texas, and extending to the county line between Parker and Hood Counties, Texas.

(6) Natural hazard lands--Geographic areas in which natural conditions exist that pose or, as a result of quarry operations, may pose a threat to the health, safety, or welfare of people, property, or the environment, including areas subject to landslides, cave-ins, large or encroaching sand dunes, severe wind or soil erosion, frequent flooding, avalanches, and areas of unstable geology.

(7) Navigable--Designated by the United States Geological Survey (USGS) as perennial on the most recent topographic map(s) published by the USGS, at a scale of 1:24,000.

(8) Operator--Any person engaged in or responsible for the physical operation and control of a quarry.

(9) Overburden--All materials displaced in an aggregates extraction operation that are not, or reasonably would not be expected to be, removed from the affected area.

(10) Owner--Any person having title, wholly or partly, to the land on which a quarry exists or has existed.

(11) Pit--An open excavation from which aggregates have been, or are being, extracted with a depth of five feet or more below the adjacent and natural ground level.

(12) Quarry--The site from which aggregates for commercial sale are being, or have been, removed or extracted from the earth to form a pit, including the entire excavation, stripped areas, haulage ramps, and the immediately adjacent land on which the plant processing the raw materials is located. The term does not include any land owned or leased by the responsible party not being currently used in the production of aggregates for commercial sale or an excavation to mine clay or shale for use in manufacturing structural clay products.

(13) Quarrying--The current and ongoing surface excavation and development without shafts, drafts, or tunnels, with or without slopes, for the extraction of aggregates for commercial sale from natural deposits occurring in the earth.

(14) Reclamation--The land treatment processes designed to minimize degradation of water quality, damage to fish or wildlife habitat, erosion, and other adverse effects from quarries. Reclamation includes backfilling, soil stabilization and compacting, grading, erosion control measures, appropriate revegetation, or other measures, as appropriate.

(15) Responsible party--Any owner, operator, lessor, or lessee who is primarily responsible for overall function and operation of a quarry located in the water quality protection area as defined in this section.

(16) Restoration--Those actions necessary to change the physical, chemical, and/or biological qualities of a receiving water body in order to return the water body to its background condition. Restoration includes on- and off-site stabilization to reduce or eliminate an unauthorized discharge, or substantial threat of an unauthorized discharge from the permitted site.

(17) Structural controls--Physical, constructed features that prevent or reduce the discharge of pollutants. Structural controls include, but are not limited to, sedimentation/detention ponds; velocity dissipation devices such as rock berms, vegetated berms, and buffers; and silt fencing.

(18) Tertiary containment--A containment method by which an additional wall or barrier is installed outside of the secondary storage vessel or other secondary barrier in a manner designed to prevent a release from migrating beyond the tertiary wall or barrier before the release can be detected.

(19) Water body--Any navigable watercourse, river, stream, or lake within the water quality protection area.

(20) Water quality protection area--The Brazos River and its contributing watershed within Palo Pinto and Parker Counties, Texas, downstream from the Morris Shepard Dam, and extending to the county line between Parker and Hood Counties, Texas.

§311.72.Applicability.

(a) This subchapter applies to a pilot program regulating quarrying within the water quality protection area designated by this subchapter, in the John Graves Scenic Riverway. This subchapter expires on September 1, 2025.

(b) This subchapter does not apply to:

(1) the construction or operation of a municipal solid waste facility regardless of whether the facility includes a pit or quarry that is associated with past quarrying;

(2) a quarry, or associated processing plant, that since on or before January 1, 1994, has been in regular operation without cessation of operation for more than 30 consecutive days and under the same ownership;

(3) the construction or modification of associated equipment located on a quarry site or associated processing plant site described in paragraph (2) of this subsection;

(4) an activity, facility, or operation regulated under Natural Resources Code, Texas Surface Coal Mining and Reclamation Act, Chapter 134; or

(5) quarries mining clay and shale for use in manufacturing structural clay products.

(c) Operations or facilities to which this subchapter does not apply under subsection (b) of this section, must maintain adequate documentation on site sufficient to demonstrate their exclusions.

(1) Documentation demonstrating ownership includes, but is not limited to: deeds, property tax receipts, leases, or insurance records.

(2) Documentation demonstrating continuous operation without cessation of operation for more than 30 consecutive days beginning on or before January 1, 1994, includes, but is not limited to: production records, sales receipts, payroll records, sales tax records, income tax records, or financial statements/reports.

(3) Documentation demonstrating the construction or operation of a municipal solid waste facility, an activity, facility, or operation regulated under Natural Resources Code, Texas Surface Coal Mining and Reclamation Act, Chapter 134; or quarries mining clay and shale for use in manufacturing structural clay products includes, but is not limited to: any permit issued by the commission, Railroad Commission of Texas, or United States Environmental Protection Agency.

§311.74.Authorization.

(a) Any responsible party shall seek and obtain a permit subject to the requirements of Chapters 205 and 305 of this title (relating to General Permits for Waste Discharges and Consolidated Permits).

(b) The following additional requirements imposed through this subchapter for discharges from quarries located within a water quality protection area in the John Graves Scenic Riverway are based on the location of the quarry.

(1) In addition to the requirements of Chapters 205 and 305 of this title, a quarry located within a water quality protection area in the John Graves Scenic Riverway must meet the following requirements:

(A) §311.75(1) of this title (relating to Permit Application Requirements);

(B) §311.79 of this title (relating to Performance Criteria for Quarries Located Within a Water Quality Protection Area in the John Graves Scenic Riverway); and

(C) §311.81(a) of this title (relating to Financial Responsibility for Quarries Located Within a Water Quality Protection Area in the John Graves Scenic Riverway).

(2) In addition to the requirements of Chapters 205 and 305 of this title and paragraph (1) of this subsection, any quarry located within the 100-year floodplain or within one mile of a water body within a water quality protection area in the John Graves Scenic Riverway must obtain an individual permit.

(3) In addition to the requirements of Chapters 205 and 305 of this title and paragraphs (1) and (2) of this subsection, all quarries located within 200 feet to 1,500 feet of a water body within a water quality protection area in the John Graves Scenic Riverway, and subject to the prohibition under §311.73(b) of this title (relating to Prohibitions), must meet the following requirements:

(A) §311.75(2) of this title;

(B) §311.80 of this title (relating to Additional Performance Criteria for Quarries Located Between 200 Feet and 1,500 Feet of a Water Body Located Within a Water Quality Protection Area in the John Graves Scenic Riverway); and

(C) §311.81(b) of this title.

(4) For any quarry subject to the provisions of paragraph (2) of this subsection , a part of which is also located outside of the 100-year floodplain of, or beyond one mile from, a water body, the requirements of paragraph (2) of this subsection are applicable to the entire quarry. The executive director may waive, modify, or otherwise adjust these requirements for that portion of the quarry located outside of the 100-year floodplain of, or beyond one mile from, a water body.

(5) For any quarry subject to the provisions of paragraph (3) of this subsection , a part of which is also located more than 1,500 feet from a water body, the requirements of paragraph (3) of this subsection will be applicable to the entire quarry. The executive director may waive, modify, or otherwise adjust these requirements for that portion of the quarry located more than 1,500 feet from a water body.

§311.76.Restoration Plan.

(a) The Restoration Plan must include a proposed plan of action for how the responsible party will restore the receiving waters to background conditions in the event of an unauthorized discharge that affects those receiving waters. The Restoration Plan, at a minimum, must:

(1) identify receiving waters at risk of an unauthorized discharge from the quarry;

(2) describe the process to be used in documenting the existing physical, chemical, and/or biological background conditions of each of the adjacent receiving waters;

(3) provide a schedule for completing the determination of background conditions of each of the receiving waters and for updating background conditions in the future, as appropriate;

(4) identify the goals and objectives of potential restoration actions;

(5) provide a reasonable range of restoration alternatives and the preferred restoration alternative that may be implemented to return the affected waters to background conditions in the event of an unauthorized discharge;

(6) describe the process for monitoring the effectiveness of the preferred restoration action, including performance criteria, that will be used to determine the success of the restoration or need for interim site stabilization;

(7) identify a process for public involvement in the selection of the restoration alternative to be implemented to restore the receiving waters to background conditions; and

(8) provide a detailed estimate of the maximum probable costs required to complete a restoration action, given the size, location, and description of the quarry and the nature of the receiving waters. The maximum probable cost must be based on the costs to a third party conducting the action without a financial interest or ownership in the quarry.

(b) Certification of the Restoration Plan must be provided, within the appropriate area or discipline, by a licensed Texas professional engineer or a licensed Texas professional geoscientist. Components of the Restoration Plan may be independently certified, as appropriate.

§311.77.Technical Demonstration.

(a) The Technical Demonstration must include, at a minimum:

(1) a time schedule for the proposed quarry from initiation to termination of operations, including reclamation;

(2) a detailed description of the type of quarrying to be conducted, including the processes/methods employed (e.g., pit mining where blasting is employed);

(3) a geological description of the quarry area, including a detailed description of the material deposit: type, geographical extent, depth, and volume; and a description of the general area geology;

(4) identification and a detailed description of any other operations on site, including raw-material processing and/or secondary products (e.g., cement) processing;

(5) identification and a detailed description of type, character, and volume of wastewater and storm water generated on site;

(6) a topographic map, at a scale appropriate to represent the quarry operation and all of the following within the boundaries of the quarry:

(A) waterbodies;

(B) existing and proposed roads including quarry access roads;

(C) existing and proposed railroads;

(D) the 100-year floodplain boundaries, if applicable;

(E) structures (e.g., office buildings);

(F) the location of all known wells including, but not limited to, water wells, oil wells, and uplugged and abandoned wells;

(G) active, post, and reclaimed quarrying areas;

(H) buffer areas;

(I) raw material, intermediate material, final product, waste product, byproduct, and/or ancillary material storage and processing areas;

(J) chemical and fuel storage areas;

(K) vehicle/equipment maintenance, cleaning, and fueling areas;

(L) vehicle/equipment loading and unloading areas;

(M) baghouses and other air treatment units exposed to precipitation; and

(N) waste disposal areas;

(7) a Surface Water Drainage and Water Accumulation Plan. The Surface Water Drainage and Water Accumulation Plan must be designed to prevent damage to fish, wildlife, and fish/wildlife habitat from erosion, siltation, and runoff from quarry operations. The Surface Water Drainage and Water Accumulation Plan must, at a minimum:

(A) describe the use and monitoring of structural controls and best management practices as identified in paragraph (8) of this subsection designed to control erosion, siltation, and runoff; and

(B) provide a topographic map, at a scale appropriate to represent the quarry operation and all of the following within the boundaries of the quarry:

(i) the location of each process wastewater and/or storm water outfall;

(ii) an outline of the drainage area that contributes storm water to each outfall;

(iii) treatment, detention, and water storage tanks and ponds;

(iv) structural controls for managing storm water and/or process wastewater; and

(v) physical features of the site that would influence storm water runoff or contribute a dry weather flow; and

(8) a Best Available Technology Evaluation. The Best Available Technology Evaluation assists staff in reviewing and determining the best available technology designed to control erosion, siltation, and runoff from the quarry to minimize disturbance and adverse effects to fish, wildlife, and related environmental resources. Where practical, the Best Available Technology Evaluation must assist staff in reviewing and determining best available technology designed to enhance fish, wildlife, and related environmental resources.

(A) The Best Available Technology Evaluation must assess the use of structural controls and best management practices.

(B) The Best Available Technology Evaluation must evaluate performance criteria outlined in §311.79 and §311.80 of this title (relating to Performance Criteria for Quarries Located Within a Water Quality Protection Area in the John Graves Scenic Riverway and Additional Performance Criteria for Quarries Located Between 200 Feet and 1,500 Feet of a Water Body Located Within a Water Quality Protection Area in the John Graves Scenic Riverway).

(C) Structural control design and construction must be certified by a licensed Texas professional engineer. Design and construction plans/specifications must be maintained on site and made available at the request of the executive director; and

(9) a procedure and schedule for reviewing the Technical Demonstration for consistency with quarry operations and site conditions and effectiveness in controlling erosion, siltation, and runoff.

(b) Certification of the Technical Demonstration must be provided, within the appropriate area or discipline, by a licensed Texas professional engineer or a licensed Texas professional geoscientist. Components of the Technical Demonstration may be independently certified, as appropriate.

§311.78.Reclamation Plan.

(a) The Reclamation Plan establishes procedures and standards for reclamation of the quarry.

(1) The Reclamation Plan must, at a minimum:

(A) provide a description of the proposed use of the disturbed area following reclamation;

(B) develop site-specific standards for reclamation appropriate to the end use proposed in subparagraph (A) of this paragraph that addresses the following:

(i) removal or final stabilization of all raw material, intermediate material, final product, waste product, byproduct, and/or ancillary material;

(ii) removal of waste or closure of all waste disposal areas;

(iii) removal of structures, where appropriate;

(iv) removal and reclamation of all temporary roads and/or railroads;

(v) backfilling, regrading, and recontouring;

(vi) slope stability for remaining highwalls and detention ponds;

(vii) revegetation of the reclaimed area giving consideration to species diversity and the use of native species;

(viii) establishment of wildlife habitat;

(ix) establishment of drainage patterns;

(x) establishment of permanent control structures (e.g., retention ponds), where necessary, to address erosion, siltation, and runoff from post quarrying and reclaimed areas; and

(xi) removal of all equipment;

(C) provide a description of how reclamation will be conducted (e.g., phased reclamation) and a timetable for the completion of reclamation activities.

(2) The Reclamation Plan must include a detailed estimate of the maximum probable cost required to complete and implement the plan. The maximum probable cost must be based on the cost to a third party conducting the reclamation without a financial interest or ownership in the quarry operation.

(b) Certification of the Reclamation Plan must be provided, within the appropriate area or discipline, by a licensed Texas professional engineer or a licensed Texas professional geoscientist. Components of the Reclamation Plan may be independently certified, as appropriate.

§311.81.Financial Responsibility for Quarries Located Within a Water Quality Protection Area in the John Graves Scenic Riverway.

(a) An owner or operator of a quarry located within a water quality protection area in the John Graves Scenic Riverway shall establish and maintain financial assurance for restoration in accordance with Chapter 37, Subchapter W of this title (relating to Financial Assurance for Quarries). The amount of financial assurance must be no less than the amount determined by the executive director as sufficient to meet the requirements of the Restoration Plan in §311.76(a)(8) of this title (relating to Restoration Plan).

(b) An owner or operator of a quarry located between 200 feet and 1,500 feet of a water body within a water quality protection area in the John Graves Scenic Riverway shall establish and maintain financial assurance for reclamation in accordance with Chapter 37, Subchapter W of this title. The amount of financial assurance must be no less than the amount determined by the executive director as sufficient to meet the requirements of the Reclamation Plan in §311.78(a)(2) of this title (relating to Reclamation Plan).

§311.82.Existing Quarries.

(a) Existing quarries required to seek and obtain authorization in accordance §311.74(b)(1) of this title (relating to Authorization), must submit a Notice of Intent as required by a commission-issued general permit, in accordance with §311.74(b)(1) of this title. Subject to the provisions of this subsection and maintaining compliance, existing quarries subject to the requirements of §311.74(b)(1) of this title that have authorization under a Texas Pollutant Discharge Elimination System Permit or Texas Land Application Permit issued under Chapters 205 and 305 of this title (relating to General Permits for Waste Discharges and Consolidated Permits), may continue to operate under the terms of that permit until the commission issues or denies authorization under this subchapter.

(b) Existing quarries required to seek and obtain authorization in accordance with §311.74(b)(2) of this title must submit an individual Texas Pollutant Discharge Elimination System or Texas Land Application Permit application not later than 180 days following the effective date of this subchapter. Subject to the provisions of this subsection and maintaining compliance, existing quarries subject to the requirements of §311.74(b)(2) of this title that have authorization under a Texas Pollutant Discharge Elimination System Permit or Texas Land Application Permit issued under Chapters 205 and 305 of this title, may continue to operate under the terms of that permit until the commission issues or denies authorization under this subchapter.

(c) Existing quarries required to seek and obtain authorization in accordance with §311.74(b)(3) of this title must submit an individual Texas Pollutant Discharge Elimination System or Texas Land Application Permit application not later than 180 days following the effective date of this subchapter. An existing quarry may not operate until the commission issues authorization under this subchapter.

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 July 14, 2006.

TRD-200603761

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: March 24, 2006

For further information, please call: (512) 239-5017

Chapter 335. INDUSTRIAL SOLID WASTE AND MUNICIPAL HAZARDOUS WASTE

Subchapter H. STANDARDS FOR THE MANAGEMENT OF SPECIFIC WASTES AND SPECIFIC TYPES OF FACILITIES

5. UNIVERSAL WASTE RULE

30 TAC §335.261

The Texas Commission on Environmental Quality (TCEQ or commission) adopts the amendment to §335.261 with changes to the proposed text as published in the February 10, 2006, issue of the Texas Register (31 TexReg 823).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULE

House Bill (HB) 2793, passed by the 79th Legislature, 2005, requires the commission to adopt rules for regulating a mercury-containing automobile convenience switch as a universal waste as defined under §335.261. Handlers of universal wastes are subject to less stringent standards for reporting, storing, transporting, and collecting these wastes.

The United States Environmental Protection Agency (EPA) published a final rule, effective August 5, 2005, that adds mercury-containing equipment (MCE) to the federal list of universal wastes regulated under the hazardous waste regulations of the Resource Conservation and Recovery Act (RCRA). The EPA concluded that regulating spent MCE, including convenience switches, as a universal waste would lead to better management of the mercury contained in this equipment and would facilitate compliance with hazardous waste requirements. The adopted rule implements provisions of HB 2793 by adopting an existing federal rule and adding MCE waste to the existing list of universal wastes.

Background on MCE

MCE consists of devices, items, or articles that contain varying amounts of elemental mercury that is integral to their functions. MCE includes several types of instruments used throughout the electric utility industry, other industries, municipalities, and households. Some commonly recognized devices are thermostats, barometers, manometers, and convenience light switches in automobiles. EPA's definition does not include mercury waste that a process of manufacturing or treatment generates as a by-product.

MCE waste is a solid waste and likely to be a hazardous waste when disposed of or reclaimed due to the toxicity characteristic (see definitions in the federal regulations in 40 Code of Federal Regulations (CFR) §261.2 and §261.3 and in TCEQ regulations in §335.1(62) and (131)). Some spent MCE contains a few grams of mercury, whereas larger articles, items, and devices can contain much more mercury. Many of these pieces of equipment would fail the toxicity characteristic leaching procedure (TCLP) level for mercury of 0.2 milligrams per liter and would therefore be a D009 characteristic hazardous waste (see federal regulations in 40 CFR §261.24, Table 1, and TCEQ regulations in §335.29).

A variety of industries generate spent MCE. Electric and gas utilities generate the greatest amount of this waste, but many other sectors, including medicine, farming, and automobile manufacturing, use MCE to regulate pressure and temperature, or to conduct electricity in switches or regulators. Generators of spent MCE, then, are from a wide range of sectors: utilities, manufacturers, commercial establishments, universities, hospitals, and households.

Rationale for the Universal Waste Rule and its Expansion

In 1995, EPA promulgated the universal waste rule to establish a streamlined hazardous waste management system for widely generated hazardous wastes as a way to encourage environmentally sound collection and proper management of the wastes. EPA included hazardous waste batteries, certain hazardous waste pesticides, mercury-containing thermostats, and hazardous waste lamps on the federal list of universal wastes. The TCEQ adopted an equivalent universal waste rule in 1997, with an amendment in 1999 to allow for paint and paint-related wastes to be managed as universal waste in Texas.

In 2005, the 79th Legislature passed HB 2793 requiring the TCEQ to adopt rules for regulating a convenience switch as a universal waste. The EPA rule, adopted August 5, 2005, in allowing for MCE to be designated as universal waste, allows convenience switches to be designated as universal waste. The commission believes that adopting the EPA rule by reference simplifies storage, handling, recycling, and disposal of MCE. It also helps ensure that spent MCE will be sent to the appropriate destination facilities, which would manage it as a hazardous waste with all applicable Subtitle C requirements. Specifically, under the commission's adopted rule, rather than having to comply with the full RCRA Subtitle C regulations, handlers and transporters who generate or manage MCE designated as universal waste are subject to the management standards under 40 CFR Part 273 and its state-equivalent, Chapter 335, Subchapter H, Division 5. Handlers include universal waste generators and collection facilities. The regulations distinguish between ''large-quantity handlers of universal waste'' (those who handle 5,000 kilograms or more total of universal waste at one time) and ''small-quantity handlers of universal waste'' (those who handle less than 5,000 kilograms or more total of universal waste at one time). The 5,000-kilogram accumulation criterion applies to the quantity of all universal wastes accumulated.

The adopted rule incorporates streamlined standards for storage, labeling and marking, preparing MCE waste for shipment off site, employee training, response to releases, and notification. However, the adopted rule is not likely to impose an additional burden on many who will fall within the expanded regulated community handling MCE. This is because the adopted packaging and labeling standards for spent MCE are already in place for used thermostats, a subset of MCE. Moreover, these streamlined standards should also encourage proper handling and recycling of the waste.

The adopted rule also subjects transporters of universal waste to less stringent requirements than the full, Subtitle C hazardous waste transportation regulations and TCEQ regulations in Chapter 335, Subchapter D. The primary difference between the universal waste transporter requirements and the full hazardous waste transportation requirements is that the transport of universal waste requires no manifest.

The commission maintains that the adopted universal waste requirements will be highly effective in mitigating risks posed by spent MCE. Specifically, the requirements for handlers to manage and transport ampules of mercury in a way that will prevent breakage, or to seal the MCE in its original housing and ship it sealed, should help ensure safe management and transport. In addition, the universal waste program requires proper training for employees on handling universal waste, responding to releases, and shipping in accordance with Department of Transportation regulations. These requirements should lower the risks posed during accumulation and transport.

The TCEQ expects that managing spent MCE as universal waste will increase the collection of this equipment. As a result, the adopted rule should increase the amount of mercury being diverted from the non-hazardous waste stream into the hazardous waste stream because it allows Texas handlers, especially those that generate this waste sporadically and in small volumes, to send it to a central consolidation point. Before EPA's adopted rule expanding universal wastes to include MCE, an entity in Texas could not consolidate these materials for more than 90 days unless it had a RCRA permit. Under the federal universal waste rule and the TCEQ's adopted universal waste rule, a handler of universal waste can send the universal waste to another handler, who can consolidate it into a larger shipment.

Another benefit of the adopted rule should be improved implementation and compliance with the state's hazardous waste regulatory program. The commission believes that the structure and requirements of the universal waste rule are compatible with the circumstances of handlers of spent MCE. Being able to handle MCE as universal waste will most likely improve compliance with the hazardous waste regulations. Because spent MCE is generated in small quantities in geographically dispersed operations, compliance with full Subtitle C requirements is difficult to achieve. Compliance with Subtitle C is particularly difficult for electric or gas utility operations that are located on customers' properties. In addition, handlers of spent MCE who are infrequent generators of hazardous waste and who might otherwise be unfamiliar with the more complex Subtitle C management structure, but who generate spent MCE, will be able to more easily send this waste for proper management. For example, under the TCEQ's adopted universal waste rule, a fire station, community center, or retail store can participate in an MCE collection program without having to get a RCRA permit, as full Subtitle C regulation would require. The TCEQ can encourage individual households and conditionally exempt small quantity generators to participate in such programs which would divert MCE from the municipal waste stream. The consolidation of MCE at facilities, which is made possible by the adopted universal waste rule, should significantly reduce the administrative and financial burden of collection and transportation of MCE. Therefore, adding spent MCE to the universal waste rule should improve compliance with the hazardous waste regulations. Improved compliance will be likely to benefit human health and the environment.

When managed improperly, mercury poses a threat to human health and the environment. The adopted addition of MCE waste to the list of universal wastes should help ensure that MCE waste ends up at a destination facility equipped to manage it properly. This adopted rule streamlines requirements only for generators and transporters of universal waste. The stringent regulation of "destination facilities" remains the same. "Destination facilities" treat, store, dispose, or recycle universal wastes. Universal waste destination facilities are subject to all currently applicable requirements for hazardous waste treatment, storage, and disposal facilities (TSDFs) and must receive a RCRA permit for such activities. For example, destination facilities must comply with the substantive requirements of the land disposal restriction (LDR) provisions of the Hazardous and Solid Waste Amendments of 1984 and the TCEQ's LDR provisions in §335.431. These include a prohibition on accumulating prohibited wastes directly on the ground; a requirement to treat waste to meet treatment standards before land placement; a prohibition on dilution; and a prohibition on accumulation, except for purposes of accumulating quantities sufficient for proper recovery, treatment, or disposal. The commission contends that compliance with the substantive requirements of the LDR program is necessary to minimize risks from mismanaging spent MCE. The commission expects that allowing spent MCE to be universal waste will make collection and transportation of this waste to an appropriate facility easier and, therefore, will reduce the amount of mercury released into the environment.

In summary, the commission maintains that expanding the universal waste list to include spent MCE is a sound way to address the environmental hazards of spent MCE. Handlers will be operating within a simple, streamlined management system with some limited oversight. The universal waste rules, as adopted, address the environmental concerns surrounding the management of MCE wastes, while at the same time putting into place a structure that better facilitates, and encourages, the increased collection of spent MCE.

SECTION BY SECTION DISCUSSION

The commission adopts administrative changes throughout these sections to be consistent with Texas Register requirements and other agency rules and guidelines and to conform to the drafting standard in the Texas Legislative Council Drafting Manual , November 2004.

Section 335.261, Universal Waste Rule

The adopted amendment to §335.261(a) updates a reference to the Federal Register .

The adopted amendment to §335.261(b)(2) changes the reference, "Texas Natural Resource Conservation Commission," to "Texas Commission on Environmental Quality."

The adopted amendment to §335.261(b)(12) changes the meaning of a reference to 40 CFR "§273.9" from equating solely to the TCEQ's definition of "thermostats," as contained in §335.261(b)(16)(E), to encompassing 40 CFR §273.9 in addition to the definition of "thermostats."

The adopted amendment to §335.261(b)(15) updates a reference from 40 CFR and adds to what, in Chapter 335, that reference is changed to.

The adopted amendment to §335.261(b)(16)(F)(iii) adds "mercury-containing equipment" to the list of hazardous wastes subject to the universal waste requirements of the section.

In §335.261(b), existing paragraph (21) is deleted since it was created solely to clarify references which no longer exist. Section 335.261(b)(22) - (29) is renumbered as §335.261(b)(21) - (28). Section 335.261(b)(29) is added to change a new reference in 40 CFR §273.33(c)(4)(i), "40 CFR Part 261, subpart C," to "Chapter 335, Subchapter R of this title (relating to Waste Classification)." In 335.261(b), existing paragraph (30) is deleted since it was created solely to clarify references which no longer exist. Section 335.261(b)(30) is added to change a new reference in 40 CFR §273.33(c)(3)(ii), "40 CFR parts 260 through 272," to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and 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. Furthermore, it does not meet any of the four applicability requirements listed in Texas Government Code, §2001.0225(a). Although this rule is adopted to protect the environment and reduce the risk to human health from environmental exposure, it is not a major environmental rule because it will not 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 rule will not adversely affect in a material way the previously mentioned aspects of the state because the rule provides for streamlined waste-management standards for certain MCE, which in turn should provide an overall benefit to the economy, certain sectors of the economy, productivity, competition, jobs, the environment, affected sectors of the state, and the public health and safety of the state. More simply stated, the adopted amendments revise the commission's hazardous waste rules in a manner which should benefit the economy while enhancing the protection of the environment and public health and safety, as per the following explanation. The overall benefit from streamlining waste management standards for certain MCE is that the new standards reduce the regulatory burden on persons generating or collecting these wastes. The streamlined waste-management standards for certain MCE should provide a benefit to the economy, certain sectors of the economy, productivity, competition, and jobs by lessening regulatory requirements, thus costing certain companies less. The rule should be a benefit by facilitating environmentally sound collection and increasing the proper recycling and processing of MCE. There should be no adverse effect because the rule is designed to maintain protection of the environment, the public health, and the public safety of the state and all sectors of the state. In other words, the TCEQ anticipates that the adopted standards will reduce regulatory requirements while facilitating an alternative for the collection of MCE and increasing the proper recycling and processing of these wastes.

Furthermore, the adopted rule does not meet any of the four applicability requirements listed in Texas Government Code, §2001.0225(a). The rule does not exceed a standard set by federal law because the purpose of this rulemaking is to adopt federal rules by reference, with no additional state standards. Requirements in the adopted rule are in accordance with the corresponding federal regulations, and they do not exceed an express requirement of state law as there is no express requirement in state law concerning universal wastes. The adopted rule does not exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program because the rule fits the framework of the corresponding federal universal waste regulations. See 40 CFR §271.21, relating to procedures, for revision of state programs and 40 CFR Part 273, relating to standards for universal waste management. The rulemaking adopts a rule under specific state law (i.e., Texas Health and Safety Code (THSC), Solid Waste Disposal Act, §361.017 and §361.024). Finally, this rulemaking is not being adopted on an emergency basis either to protect the environment or to reduce risks to human health from environmental exposure.

TAKINGS IMPACT ASSESSMENT

In accordance with Texas Government Code, §2007.043, the commission has prepared a takings impact assessment for the adopted rule. The following is a summary of that assessment. The specific purpose of the adopted rule is to provide an alternative for the collection of MCE, facilitating environmentally sound collection and increasing the proper recycling and processing of MCE. The adopted rule should substantially advance this purpose through environmentally protective, streamlined standards relating to universal wastes meeting the definition of MCE. Promulgation and enforcement of the adopted rule will not affect private property because the rule provides an alternative set of management standards for MCE in lieu of other, more stringent hazardous waste regulations, representing a streamlined approach. The adopted standards are not more stringent than existing standards. In addition, the reduction of regulatory requirements will be taken only at the initiative of certain persons managing MCE. For these reasons, the adopted rule will not be a burden to private real property and will not constitute a taking under Texas Government Code, Chapter 2007. The adopted rule will not affect a landowner's rights in private real property.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission reviewed the rulemaking and found that the adopted rule is subject to the Texas Coastal Management Program (CMP) and must be consistent with all applicable goals and policies of the CMP. In accordance with 31 TAC §505.22, the commission has prepared a consistency determination for the adopted rule and has found that it is consistent with the applicable CMP goals and policies. The following is a summary of that determination. The CMP goals applicable to the rulemaking are to protect, preserve, restore, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas (CNRAs). CMP policies focus on construction and operation of solid waste treatment, storage, and disposal facilities, such that new solid waste facilities and areal expansions of existing solid waste facilities shall be sited, designed, constructed, and operated to prevent releases of pollutants that may adversely affect CNRAs and, at a minimum, comply with standards established under the Solid Waste Disposal Act, 42 United States Code, §§6901 et seq . Promulgation and enforcement of this rule will be consistent with the applicable CMP goals and policies because the rule will facilitate the environmentally sound collection of MCE wastes, increase the proper recycling and processing of MCE wastes, and enable programs developed to reduce the quantity of these wastes going to municipal solid waste landfills or incinerators. The rule should also help assure that the wastes go to appropriate processing and recycling facilities under full RCRA Subtitle C hazardous waste regulatory controls. Thus, the rule will serve to protect, preserve, restore, and enhance the diversity, quality, quantity, functions, and values of CNRAs. Adding MCE to the list of universal wastes will not impact new solid waste facilities and areal expansions of existing solid waste facilities. The commission has determined that the specific actions detailed in this section and earlier in this preamble under the sections explaining the adopted rule, concerning explanation of the adopted rule, final regulatory impact assessment, and takings impact assessment comply with the goals and policies of the CMP. In addition, the adopted rule does not violate any applicable provisions of the CMP's stated goals and policies.

PUBLIC COMMENT

The TCEQ did not receive any comments on the rule proposal. The comment period was 30 days. It began on February 10, 2006, and ended on March 13, 2006.

STATUTORY AUTHORITY

The amendment is adopted under Texas Water Code (TWC), §5.103 and §5.105, which provide the commission with the authority to adopt any rules necessary to carry out its powers and duties under the provisions of the TWC or other laws of this state; and under THSC, Solid Waste Disposal Act, §361.017 and §361.024, which authorize the commission to regulate industrial solid waste and municipal hazardous waste and to adopt rules consistent with the general intent and purposes of the Solid Waste Disposal Act.

The adopted amendment implements THSC, Chapter 375, which relates to convenience switches from motor vehicles to be classified as universal waste.

§335.261.Universal Waste Rule.

(a) This section establishes requirements for managing universal wastes as defined in this section, and provides an alternative set of management standards in lieu of regulation, except as provided in this section, under all otherwise applicable chapters under 30 Texas Administrative Code. Except as provided in subsection (b) of this section, 40 Code of Federal Regulations (CFR) Part 273 is adopted by reference as amended and adopted in the Federal Register through August 5, 2005 (70 FR 45508).

(b) 40 CFR Part 273, except §273.1, is adopted subject to the following changes.

(1) The term "regional administrator" is changed to "executive director" or "commission" consistent with the organization of the commission as set out in the Texas Water Code, Chapter 5.

(2) The terms "U.S. Environmental Protection Agency" and "EPA" are changed to "the Texas Commission on Environmental Quality," "the agency," or "the commission" consistent with the organization of the commission as set out in Texas Water Code, Chapter 5. This paragraph does not apply to 40 CFR §273.32(a)(3) or §273.52 or to references to the following: "EPA Acknowledgment of Consent" or "EPA Identification Number."

(3) The term "treatment" is changed to "processing."

(4) The term "universal waste" is changed to "universal waste as defined under §335.261(b)(16)(F) of this title (relating to Universal Waste Rule)."

(5) The term "this part" is changed to "Chapter 335, Subchapter H, Division 5 of this title (relating to Universal Waste Rule)."

(6) In 40 CFR §273.2(a) and (b), references to "40 CFR part 266, subpart G," are changed to "§335.251 of this title (relating to Applicability and Requirements)."

(7) In 40 CFR §273.2(b)(2), the reference to "part 261 of this chapter" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(8) In 40 CFR §273.3(b)(1), the reference to "40 CFR §262.70" is changed to "§335.77 of this title (relating to Farmers)." Also, the phrase "(40 CFR §262.70 addresses pesticides disposed of on the farmer's own farm in a manner consistent with the disposal instructions on the pesticide label, providing the container is triple rinsed in accordance with 40 CFR 261.7(b)(3))" is deleted.

(9) In 40 CFR §273.3(b)(2), the reference to "40 CFR parts 260 through 272" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(10) In 40 CFR §273.3(b)(3), the reference to "part 261 of this chapter" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(11) In 40 CFR §273.3(d)(1)(i) and (ii), references to "40 CFR §261.2" are changed to "§335.1 of this title (relating to Definitions)."

(12) In 40 CFR §273.4(a), the reference to "§273.9" as it relates to the definition of "mercury-containing equipment" is amended to include the commission definition of "thermostats" as contained in §335.261(b)(16)(E) of this title (relating to Universal Waste Rule) and in 40 CFR §273.4(b)(1), the reference to "part 261 of this chapter" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(13) In 40 CFR §273.5(b)(1), the reference to "part 261 of this chapter" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(14) In 40 CFR §273.8(a)(1), the reference to "40 CFR §261.4(b)(1)" is changed to "§335.1 of this title (relating to Definitions)" and the reference to "§273.9" is changed to "§335.261(b)(16)(F) of this title (relating to Universal Waste Rule)."

(15) In 40 CFR §273.8(a)(1), the reference to "40 CFR §261.4(b)(1)" is changed to "§335.78 of this title (relating to Special Requirements for Hazardous Waste Generated by Conditionally Exempt Small Quantity Generators)" and to "§335.402(5) of this title (relating to Definitions)" and the reference to "§273.9" is changed to "§335.261(b)(16)(F) of this title (relating to Universal Waste Rule)."

(16) In 40 CFR §273.9, the following definitions are changed to the meanings described in this paragraph.

(A) Destination facility--A facility that treats, disposes, or recycles a particular category of universal waste, except those management activities described in 40 CFR §273.13(a) and (c) and 40 CFR §273.33(a) and (c), as adopted by reference in this section. A facility at which a particular category of universal waste is only accumulated is not a destination facility for purposes of managing that category of universal waste.

(B) Generator--Any person, by site, whose act or process produces hazardous waste identified or listed in 40 CFR Part 261 or whose act first causes a hazardous waste to become subject to regulation.

(C) Large quantity handler of universal waste--A universal waste handler (as defined in this section) who accumulates at any time 5,000 kilograms or more total of universal waste (as defined in this section), calculated collectively. This designation as a large quantity handler of universal waste is retained through the end of the calendar year in which 5,000 kilograms or more total universal waste is accumulated.

(D) Small quantity handler of universal waste--A universal waste handler (as defined in this section) who does not accumulate at any time 5,000 kilograms or more total of universal waste (as defined in this section), calculated collectively.

(E) Thermostat--A temperature control device that contains metallic mercury in an ampule attached to a bimetal sensing element, and mercury-containing ampules that have been removed from these temperature control devices in compliance with the requirements of 40 CFR §273.13(c)(2) or §273.33(c)(2) as adopted by reference in this section.

(F) Universal waste--Any of the following hazardous wastes that are subject to the universal waste requirements of this section:

(i) batteries, as described in 40 CFR §273.2;

(ii) pesticides, as described in 40 CFR §273.3;

(iii) mercury-containing equipment, including thermostats, as described in 40 CFR §273.4;

(iv) paint and paint-related waste, as described in §335.262(b) of this title (relating to Standards for Management of Paint and Paint-Related Waste); and

(v) lamps, as described in 40 CFR §273.5.

(17) In 40 CFR §273.10, the reference to "40 CFR §273.9" is changed to "§335.261(b)(16)(D) of this title (relating to Universal Waste Rule)."

(18) 40 CFR §273.11(b) is changed to read as follows: "Prohibited from diluting or treating universal waste, except when responding to releases as provided in 40 CFR §273.17; managing specific wastes as provided in 40 CFR §273.13; or crushing lamps under the control conditions of §335.261(e) of this title (relating to Universal Waste Rule)."

(19) In 40 CFR §273.13(a)(3)(i), the reference to "40 CFR parts 260 through 272" and the reference to "40 CFR part 262" are changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(20) In 40 CFR §273.13(c)(2)(iii) and (iv), references to "40 CFR §262.34" are changed to "§335.69 of this title (relating to Accumulation Time)."

(21) In 40 CFR §273.13(d)(1), the phrase "adequate to prevent breakage" is changed to "adequate to prevent breakage, except as specified in §335.261(e) of this title (relating to Universal Waste Rule)."

(22) In 40 CFR §273.17(b), the reference to "40 CFR parts 260 through 272" and the reference to "40 CFR part 262" are changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(23) In 40 CFR §273.20(a), the reference to "40 CFR §§262.53, 262.56(a)(1) through (4), (6), and (b) and 262.57" is changed to "§335.13 of this title (relating to Recordkeeping and Reporting Procedures Applicable to Generators Shipping Hazardous Waste or Class 1 Waste and Primary Exporters of Hazardous Waste) and §335.76 of this title (relating to Additional Requirements Applicable to International Shipments)."

(24) In 40 CFR §273.20(b), the reference to "subpart E of part 262 of this chapter" is changed to "§335.13 of this title and §335.76 of this title."

(25) In 40 CFR §273.30, the reference to "§273.9" is changed to "§335.261(b)(16)(C) of this title (relating to Universal Waste Rule)."

(26) 40 CFR §273.31(b) is changed to read as follows: "Prohibited from diluting or treating universal waste, except when responding to releases as provided in 40 CFR §273.37; managing specific wastes as provided in 40 CFR §273.33; or crushing lamps under the control conditions of §335.261(e) of this title (relating to Universal Waste Rule)."

(27) In 40 CFR §273.33(a)(3)(i), the reference to "40 CFR parts 260 through 272" and the reference to "40 CFR part 262" are changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(28) In 40 CFR §273.33(c)(2)(iii) and (iv), the references to "40 CFR §262.34" are changed to "§335.69 of this title (relating to Accumulation Time)."

(29) In 40 CFR §273.33(c)(4)(i), the reference, "40 CFR part 261, subpart C," is changed to "Chapter 335, Subchapter R of this title (relating to Waste Classification)."

(30) In 40 CFR §273.33(c)(3)(ii), the reference, "40 CFR parts 260 through 272," is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(31) In 40 CFR §273.33(d)(1), the phrase "adequate to prevent breakage" is changed to "adequate to prevent breakage, except as specified in §335.261(e) of this title (relating to Universal Waste Rule)."

(32) In 40 CFR §273.37(b), the reference to "40 CFR parts 260 through 272" and the reference to "40 CFR part 262" are changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(33) In 40 CFR §273.40(a), the reference to "40 CFR §§262.53, 262.56(a)(1) through (4), (6), and (b) and 262.57" is changed to "§335.13 of this title (relating to Recordkeeping and Reporting Procedures Applicable to Generators Shipping Hazardous Waste or Class 1 Waste and Primary Exporters of Hazardous Waste) and §335.76 of this title (relating to Additional Requirements Applicable to International Shipments)."

(34) In 40 CFR §273.40(b), the reference to "subpart E of part 262 of this chapter" is changed to "§335.13 of this title and §335.76 of this title."

(35) In 40 CFR §273.52(a), the reference to "40 CFR part 262" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(36) In 40 CFR §273.52(b), the reference to "40 CFR part 262" is changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(37) In 40 CFR §273.54(b), the reference to "40 CFR parts 260 through 272" and the reference to "40 CFR part 262" are changed to "Chapter 335 of this title (relating to Industrial Solid Waste and Municipal Hazardous Waste)."

(38) In 40 CFR §273.60(a), the reference to "§273.9" is changed to "§335.261(b)(16)(A) of this title (relating to Universal Waste Rule)" and the reference to "parts 264, 265, 266, 268, 270, and 124 of this chapter" is changed to " 30 Texas Administrative Code (relating to Environmental Quality)."

(39) In 40 CFR §273.60(b), the reference to "40 CFR §261.6(c)(2)" is changed to "§335.24 of this title (relating to Requirements for Recyclable Materials and Nonhazardous Recyclable Materials)."

(40) In 40 CFR §273.80(a), the reference to "40 CFR §260.20 and §260.23" is changed to "§20.15 of this title (relating to Petition for Adoption of Rules) and §335.261(c) of this title (relating to Universal Waste Rule)."

(41) In 40 CFR §273.80(b), the reference to "40 CFR §260.20(b)" is changed to "§20.15 of this title (relating to Petition for Adoption of Rules)."

(42) In 40 CFR §273.81(a), the reference to "40 CFR §260.10" is changed to "§335.1 of this title (relating to Definitions) and the reference to "§273.9" is changed to "§335.261(b)(16)(F) of this title (relating to Universal Waste Rule)."

(c) Any person seeking to add a hazardous waste or a category of hazardous waste to the universal waste rule may file a petition for rulemaking under this section, §20.15 of this title, and 40 CFR Part 273, Subpart G as adopted by reference in this section.

(1) To be successful, the petitioner must demonstrate to the satisfaction of the commission that regulation under the universal waste rule: is appropriate for the waste or category of waste; will improve management practices for the waste or category of waste; and will improve implementation of the hazardous waste program. The petition must include the information required by §20.15 of this title. The petition should also address as many of the factors listed in 40 CFR §273.81 as are appropriate for the waste or category of waste addressed in the petition.

(2) The commission will grant or deny a petition using the factors listed in 40 CFR §273.81. The decision will be based on the commission's determinations that regulation under the universal waste rule is appropriate for the waste or category of waste, will improve management practices for the waste or category of waste, and will improve implementation of the hazardous waste program.

(3) The commission may request additional information needed to evaluate the merits of the petition.

(d) Any waste not qualifying for management under this section must be managed in accordance with applicable state regulations.

(e) Crushing lamps is permissible only in a crushing system for which the following control conditions are met:

(1) an exposure limit of no more than 0.05 milligrams of mercury per cubic meter is demonstrated through sampling and analysis using Occupational Safety and Health Administration (OSHA) Method ID-140 or National Institute for Occupational Safety and Health Method Number 6009, based on an eight-hour time-weighted average of samples taken at the breathing zone height near the crushing system operating at the maximum expected level of activity;

(2) compliance with the notification requirements of §106.262 of this title (relating to Facilities (Emission and Distance Limitations) (Previously SE 118)) is demonstrated;

(3) documentation of the demonstrations under paragraphs (1) and (2) of this subsection is provided in a written report to the executive director; and

(4) the executive director approves the crushing system in writing.

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 July 14, 2006.

TRD-200603746

Robert Martinez

Acting Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: August 3, 2006

Proposal publication date: February 10, 2006

For further information, please call: (512) 239-0177