Subchapter B. GENERAL WASTE MANAGEMENT

The Railroad Commission of Texas (Commission) proposes new §§4.101, 4.103, 4.106, 4.109, 4.112, 4.115, 4.118, 4.121, 4.124, 4.127, 4.130, 4.133, 4.136, 4.139, 4.142, 4.145, 4.148, 4.151, 4.154, 4.157, 4.160, 4.163, 4.166, 4.169, 4.172, 4.175, 4.178, 4.181, 4.184, 4.187, 4.190, 4.193, and 4.196, relating to Purpose; Definitions; Federal Regulations; Prohibited Waste Management Methods; Prohibited Pits; Authorized Disposal Methods for Certain Wastes; Authorized Pits; General Standards for Permit Issuance; Siting Standards for Permitted Pits and Landfarms; Construction Standards for Permitted Pits and Landfarms; Operating Standards for Permitted Pits and Landfarms; Closure Standards for Permitted Pits and Landfarms; Documentation of Compliance; Information Required for Permit Application for a Noncommercial Facility; Additional Information Required for Permit Application for a Commercial Facility; Notice, Protests, and Hearings; Applicability; Reporting of Surface Water Pollution; Corrective Action; Suspension of Production; Oil and Gas Waste Haulers; Waste Tracking and Recordkeeping; Alternatives; Emergency Permits; Minor Permits; Responsibility for Waste Management; Modification, Suspension, and Termination of Permits; Penalties; Applicability; Specific Policies; Consistency Determinations; Thresholds for Referral; and Cleanup by the Commission, in new Subchapter B of Texas Administrative Code, Title 16, Chapter 4. The proposed new rules are intended to strengthen requirements for prevention of pollution of surface and subsurface waters; conform the wording of the rules to reflect current Commission practice; incorporate into the rules the separate Commission publication entitled "Questions and Answers to Rule 8," which was developed after §3.8 was substantially amended in 1984; and respond, in part, to recommendations that arose out of a review of Commission regulatory practices conducted by a stakeholder team selected by the Interstate Oil and Gas Compact Commission (IOGCC).

The Commission simultaneously proposes the review of §3.8, in accordance with Texas Government Code, §2001.039, and the repeal of §3.8, the provisions of which are being expanded and proposed as the new rules in Chapter 4, Subchapter B. The notices of proposed review and proposal to repeal were filed with the Texas Register concurrently with this proposal. As stated in the rule review notice, the agency's reasons for adopting rules relating to the protection of groundwater continue to exist.

In open meeting conference on February 21, 2002, the Commission directed its Staff to hold a series of workshops for informal public comment on the draft proposal to amend the requirements of §3.8 and readopt them as new rules in new Chapter 4, Subchapter B.

During March 2002, Staff conducted workshop in Midland, Wichita Falls, Houston, Kilgore, Austin, and Amarillo. A total of 188 people attended, including 152 representing industry, six representing land and royalty owners, seven with groundwater conservation districts, and 23 who identified themselves as representing "other." At the workshops, the Railroad Commission Staff briefly explained proposed changes to the rules and solicited oral or written comment.

The Staff received written comments from 120 persons, many of whom were not in attendance at the workshops. In response to comments received at the workshops and in writing, Staff made several minor and relatively major changes to the draft version of the rules that was discussed at the workshops. A discussion of the major issues and Staff's response follows.

One issue raised at the workshops and in written comments concerned authorized discharge to ground surface of storm water and hydrostatic test water from new pipe. Draft proposed new Subchapter B requires surface owner permission and limits chlorides to 500 mg/l and benzene to 0.050 mg/l. The current §3.8 does not authorize discharge of hydrostatic test water or stormwater. The proposal to require written permission of the surface owner for land surface discharge is consistent with a similar requirement for on-site landfarming of low chloride water base drilling fluid. For discharge of storm water from a firewall, Staff made no change to the requirement for surface owner permission. For discharge of hydrostatic test water, Staff clarified that written surface owner permission is required only if the discharge is not limited to the pipeline easement or right-of-way.

A second general issue concerned siting restrictions for authorized pits. Draft proposed new Subchapter B would require that an authorized pit be located no closer than 500 feet from water wells. Currently, §3.8 does not contain distance or depth restrictions. Commenters assert that recent city ordinances do not require such distances. One commenter advised that easements for public water supply wells range from 150 to 500 feet. Staff changed from 500 to 150 feet the distance required between an authorized pit and water wells.

A third issue concerned siting restrictions for authorized landfarming of low chloride, water base drilling fluid from a reserve pit. The proposed new Subchapter B would require that landfarming may not be performed within 500 feet of surface water and that the slope of the land to be landfarmed may not exceed 5%. Currently §3.8 requires that landfarming be performed such that runoff cannot occur, but contains no specific restrictions with respect to distance from surface water or slope. Commenters asserted that a distance of 500 feet from surface water is not possible in Houston and Kilgore districts. Staff agreed and changed the distance to 150 feet from surface water. Staff believes that a limit on slope of land to be landfarmed is necessary to ensure that the drilling fluid will not runoff onto adjacent property and/or into surface water and, therefore, did not change the proposed slope restriction.

A fourth issue concerned lining of certain authorized pits. The version of proposed draft Subchapter B discussed at the workshops would require a liner for any reserve pit that contains oil based mud, has chloride content of greater than 6100 mg/l, is on alluvium, or is located where ground water is less than 20 feet from the surface. Currently, §3.8 contains no specific liner requirements but requires that any authorized pit be constructed and operated such that there is no pollution. Commenters asserted that in-situ substratum in many areas would meet liner requirements. Other commenters asserted that the chloride concentration in a reserve pit that would require a liner should be lowered to 3,000 mg/l.

Staff proposed liner requirements for certain reserve pits as a result of factors such as permeability of soil, type of waste in pit, and length of time fluids remain in the pit. The proposed rule would allow either an artificial (plastic) or constructed-earthen liner. After reviewing all the comments concerning this issue, Staff determined to allow either artificial (plastic) or constructed-earthen liner for those reserve pits proposed to require a liner, unless the in-situ substratum meets the hydraulic conductivity of 1 x 10 ^{- 7} cm/sec. Further, Staff lowered the proposed chloride limit for unlined reserve pits to 3000 mg/l.

The version of proposed Subchapter B discussed at the workshops would require an artificial liner all completion/workover pits. Currently §3.8 does not contain specific liner requirements, but prohibits pollution from the use and closure of such pits. Commenters asserted that many completion/workover pits are used, dewatered, and backfilled in two to five days (Wichita Falls). Commenters further asserted that the reuse of completion/workover pit locations would destroy the artificial liner and create liner debris at the surface. After reviewing all comments concerning this issue, Staff determined to change the language to require either an artificial (plastic) or constructed-earthen liner, unless in-situ substratum meets hydraulic conductivity of 1 x 10-7 cm/sec or if completion/workover pit is used, dewatered, and backfilled within a time period of no greater than 7 days and not in alluvium and over a water table greater than 20 feet.

There was much discussion about liner standards. Proposed Subchapter B would require that an artificial liner be at least 12 mil in thickness and a constructed- earthen liner at least 2 feet in thickness, placed in 6 inch lifts and compacted. Statewide Rule 8 currently contains no specific liner specifications or requirements. Commenters asserted that artificial liners are unwieldy and costly and that operators generally use liner in the field with thickness of between six and 10 mils. Staff made no change to the proposed artificial liner thickness requirements because it has been provided with no information as yet to verify that a 6-10 mil liner is appropriate in all circumstances. Commenters also asserted that a thickness of two feet for constructed-earthen liners is unnecessary and that in-situ substratum in some areas can meet the hydraulic conductivity requirement. After review and discussion, Staff included in the proposed Subchapter B requirements language that would allow construction of a pit in in-situ substratum that meets hydraulic conductivity of 1 x 10-7 cm/sec in lieu of artificial or constructed-earthen liner.

Another issue concerned the proposed operation requirements for authorized pits, specifically the requirement that a person maintain a freeboard of at least two (2) feet in a pit. Currently §3.8 does not contain specific requirements for freeboard or berms. Commenters asserted that a freeboard of two feet is not enough in certain areas and too much in others and that any freeboard requirement should be tied to rainfall. Staff believes that rainfall is not the only reason for maintaining certain freeboard. A specific standard assures a freeboard that is generally adequate in all circumstances. Staff made no change to the freeboard requirement.

One other issue raised by commenters concerned the requirements for closure of authorized pits. The proposed language would require that reserve pits with a chloride concentration of greater than 6100 mg/l be dewatered in 30 days and backfilled and compacted in 120 days and that other reserve pits be dewatered, backfilled and compacted in 120 days. Currently §3.8 allows a year to dewater, backfill and compact a reserve pit that contains low chloride water base drilling fluid with a chloride concentration of 6100 mg/.l or less and allows 30 days to dewater and a year to backfill and compact other reserve pits. Commenters assert that 120 days is not adequate to allow reserve pit to dry out for proper closure. Staff changed the proposed language to allow 180 days to dewater, backfill and compact all authorized pits and to require a liner for reserve pits with a chloride content of greater than 3000 mg/l. Staff proposes to retain the requirement to dewater within 30 days a reserve pit with a chloride content of greater than 3000 mg/l.

Another issue concerned liner integrity during pit closure. The version of proposed Subchapter B that was discussed at the workshops would require that a person maintain liner integrity during closure of a pit that is required to be lined. Currently §3.8 contains no specific liner requirements. Commenters asserted that integrity of the liner cannot be maintained during closure. They asserted that artificial liners are torn up during closure and pieces of plastic "float" to the ground surface, whether or not a cap is installed over the closed pit. After discussion, Staff revised the proposed language to allow either an artificial or constructed-earthen liner in those instances where the rule requires a liner and to delete the requirement to maintain liner integrity during closure.

Another issue concerned authorizing burial of oil and gas waste. Subchapter B would continue the practice of authorizing burial of dewatered pit solids in a reserve pit. Commenters asserted that the Commission should take the opportunity now to prohibit leaving any oil and gas waste in place, that anything buried will eventually pollute groundwater, and that all waste should be taken to off-site disposal facility. Staff believes that proposed lining and closure standards will be adequate to prevent pollution of subsurface water from burial of reserve pit solids and made no change to the proposed language.

One final major issue concerned protection of surface and subsurface water. Both the language currently in §3.8 and the language in proposed Subchapter B would require protection of all surface and subsurface water. Some commenters asserted that liners should not be required in areas where ground water is not "usable." Staff determined that the statutory authority for the rule and subchapter requires protection of "surface and subsurface water" and does not distinguish between classes of water. Staff believes that the Commission must use the most protective term in a general rule for statewide application and, therefore, made no change to the proposed language in response to this comment.

Throughout the proposed new rules (collectively referred to as "Subchapter B"), the Commission proposes to substitute the term "Commission" for "director" as it is used in existing §3.8. A proposed new definition of "Commission," meaning the Commission, the director of the Oil and Gas Division, or the director's designee, will allow the Commission the latitude to assign various duties under Subchapter B to appropriate staff without the need of formally amending the subchapter whenever staff job responsibilities or titles might change. In addition, the Commission proposes to change any reference in existing §3.8 to the Texas Natural Resource Conservation Commission to the "Texas Natural Resource Conservation Commission or its successor agency" to reflect the impending change of the agency's name as a result of legislation enacted in 2001.

Proposed new §4.101 (relating to Purpose) contains the provisions of existing §3.8(b), which prohibits a person conducting activities subject to regulation by the Commission from causing or allowing pollution of surface or subsurface water in the state. The existing provisions in §3.8(c), which pertain to exploratory wells, are not proposed in new Subchapter B, because exploratory wells are regulated under other Commission rules and therefore provisions of existing §3.8(c) are not necessary.

Proposed new §4.103 is an amended version of existing §3.8(a) that revises certain current definitions; deletes certain definitions; adds new definitions; and arranges the definitions in alphabetical order. The definitions proposed in §4.103 are generally the same as those in existing §3.8(a), with the following notable changes.

The definition of "activities associated with the exploration, development, and production of oil or gas or geothermal resources," currently found in §3.8(a)(30), is proposed to include injection wells, core holes and seismic holes.

The definition of "alluvium and Quaternary sand and gravel" as unconsolidated sediments consisting of gravel, sand, and/or silt deposited by rivers, streams, or wind which typically exhibit high porosity and high permeability," is proposed as a new definition because it is useful in describing geologic conditions where lining of pits is required.

As proposed, the definition of "basic sediment pit, brine pit; carrier; collecting pit" deletes a reference to burn pits currently found in §3.8(a)(1).

The Commission proposes to add a definition for the term "bell hole" to describe a feature which is not considered a pit. As proposed, the term would mean a temporary hole dug to enable repairs to a buried pipeline or to collect liquids that must be drained from a pipeline during repair operations. For the purposes of proposed Subchapter B, a bell hole that is emptied immediately, cleaned up if necessary and filled in immediately after use is not a pit and is therefore not subject to any of the requirements in this subchapter for authorized or permitted pits.

The definition of "brine pit" is proposed to simplify that found in §3.8(a)(2) and to combine it with definition of "brine mining pit," which will no longer have the separate definition now found in §3.8(a)(32).

The proposed definition of "cap," as a continuous layer of materials, synthetic or natural, placed over an area of waste disposal that serves to restrict the release or migration of oil field fluids or oil and gas wastes is included because it is useful in describing the protective construction element required for the closure of some pits.

The definition of "capillary barrier" as a high porosity layer installed over an area of waste disposal in lieu of a cap to prevent upward migration of waste constituents in areas where the annual evaporation rate is greater than the annual precipitation rate, the annual precipitation rate is 25 inches or less, and the depth to ground water is greater than 100 feet, is proposed to describe a kind of cap which retards or prevents upward movement of saline fluid, allowed in parts of the state where evaporation exceeds percolation. There is no definition for this term in §3.8(a).

The proposed definition of "collecting pit" simplifies the current definition in §3.8(a)(3).

The Commission proposes to define "commercial facility" as one whose owner or operator receives compensation from others for the storage, handling, recycling, reclamation, treatment, or disposal of oil field fluids or oil and gas wastes that are wholly or partially trucked or hauled to the facility, and whose primary business purpose is to provide these services for compensation. This term is not defined in §3.8(a).

The proposed definition of "Commission" clarifies that the commission may be the Railroad Commission of Texas, the Oil and Gas Division Director, or the director's designee. The term "director," now found in §3.8(a)(20), is not defined in proposed new §4.103 because it is incorporated into the proposed definition of "Commission."

The proposed definition of the term "dewater" replaces the definition of the term "to dewater." The proposed definition, to remove as much of the free water, free hydrocarbons, and other free liquids as practicable, is slightly modified from that found in §3.8(a)(23).

The proposed definition of the term "disposal" replaces the definition of the term "to dispose," found in §3.8(a)(24). The proposed definition, the act of conducting, draining, discharging, emitting, throwing, releasing, depositing, burying, dumping, placing, or landfarming of any oil field fluid, oil and gas waste, or other substance or material subject to regulation by the Commission or to cause or allow any such act, is slightly modified from the current definition.

There are two proposed definitions of technical terms not currently found in §3.8(a). As proposed, the definition of "electrical conductivity (EC)," is a unit of measurement employed to assess soil salinity. The proposed definition of "exchangeable sodium percentage (ESP)" describes a unit of measurement used to assess soil's potential threat to agriculture due to sodium content.

The proposed definition of "flare pit" is expanded from its existing definition in §3.8(a)(8) to include incidental amounts of reservoir fluids and use during maintenance activities.

The term "freeboard," not currently defined in §3.8(a), is proposed to be defined as the height of an interior pit wall from the uppermost content level to the top of the wall.

The Commission proposes to combine the definitions for "fresh makeup water pit," found in §3.8(a)(9), and "fresh mining water pit," found in §3.8(a)(33), under the term "fresh makeup/mining water pit."

As proposed, the definition of "gas plant evaporation/retention pit" clarifies the definition currently found in §3.8(a)(10) by stating that a gas processing plant includes a pit used for storage or disposal of cooling tower blowdown, water condensed from natural gas, or other waste water generated a natural gas liquids processing plant.

The definition proposed for the term "hydrocarbon condensate," not currently defined in §3.8(a), as the light, hydrocarbon liquids produced in association with natural gas, describes a material acceptable for temporary storage in an authorized flare pit. The proposed definition of "liner," the continuous layer of impermeable materials, synthetic or natural, beneath and on the sides of a pit that restricts the downward and lateral release or migration of oil field fluids or oil and gas wastes, is included because a liner is required for certain authorized and permitted pits. There is no definition of this term in §3.9(a).

The Commission proposes to define "natural gas or natural gas liquids processing plant" as a plant whose primary function is the extraction of natural gas liquids from field gas or fractionation of natural gas liquids. The term does not include a separately located natural gas treating plant for which the primary function is the removal of carbon dioxide, hydrogen sulfide, or other impurities from the natural gas stream. A separator, dehydration unit, heater treater, sweetening unit, compressor, or similar equipment would be considered a part of a natural gas or natural gas liquids processing plant only if it is located at a plant the primary function of which is the extraction of natural gas liquids from field gas or fractionation of natural gas liquids. This term is not defined in §3.8(a).

The proposed definition of "oil and gas wastes" modifies the definition in §3.8(a)(26) and clarifies that a hazardous waste generated at a gas plant is not an oil and gas waste until the Commission receives authority to administer the federal program for management of hazardous oil and gas waste as defined by §3.98 (relating to Hazardous Oil and Gas Waste).

The definition proposed for "pit" clarifies and describes what the Commission considers to be a pit subject to regulation. The term is not currently defined in §3.8(a). Under the proposal, a "pit" is a natural topographic depression, man-made excavation, or diked or bermed area that is designed or intentionally used to hold oil field fluids or oil and gas wastes. A buried tank or an excavation made for underground storage or disposal of oil field fluids or oil and gas wastes is a pit for purposes of this subchapter. The term does not include a bell hole or an injection or disposal well or diked or bermed area used solely for secondary containment or fire prevention purposes.

The Commission proposes to define "pressure maintenance plant or repressurizing plant" as a plant for processing natural gas for reinjection for reservoir pressure maintenance or repressurizing in a natural gas recycling project. Neither of these terms would include a compressor station along a natural gas pipeline system or a pump station along a crude oil pipeline system. These terms are not currently defined in §3.8(a).

The proposed definition for "public water supply," not currently defined in §3.8(a), is a source of water used by the public for human consumption, and is relevant to certain regulations.

The Commission proposes a definition of the term "receiver" that is the same as that in §3.8(a)(19) but adds "recycles" as one of the activities that defines the term. The proposed definition of the term "recycle" describes the recycling process for oil and gas waste as storing, handling and/or treating oil and gas waste for use or reuse as, or for processing into, a legitimate commercial product. This term is not currently defined in §3.8(a).

The proposed definition of "reserve pit" is the same as in existing §3.8(a)(12), but deletes the reference to slush pit and mud pit.

The term "sewage," not currently defined in §3.8(a), is proposed to mean oil and gas waste that is primarily organic and biodegradable or decomposable and generally originates as human, animal, or plant waste from activities such as the use of toilet facilities, washing, bathing, and food preparation.

The Commission proposes a definition of the term "skimming pit" that deletes the qualifying location language found in the current definition in §3.8(a)(14). The definition proposed for "small sump" is a pit lined with concrete, corrosion-resistant metal, or pre-molded synthetic material that has a capacity of 500 gallons or less. This term is not currently defined in §3.8(a).

The definition proposed for "sodium adsorbtion ratio(SAR), describes a type measurement used to evaluate the potential damage associated with sodium salts. There is no definition for this term in §3.8(a).

The proposed definition for "stormwater," not currently defined in §3.8(a), is rainfall runoff, snow melt runoff, surface runoff, and drainage.

The definition of "washout pit" is proposed to delete the reference to location found in the existing definition in §3.8(a)(15). The definition of "water condensate pit" is proposed to delete reference to pipeline drip or gas compressor station and to delete the term "fresh" found in the existing definition in §3.8(a)(16).

The proposed definition of "wetland," not currently defined in §3.8(a), describes a type of surface water as defined in Texas Water Code, Chapter 11 (relating to Wetlands).

The rules in proposed new Division 2 cover authorized waste management methods and are generally equivalent to the provisions in current §3.8(d), which relate to pollution control. Proposed new §4.109 (relating to Prohibited Waste Management Methods), is an amended and expanded version of the provisions in existing §3.8(d)(1), which relate to prohibited disposal methods. Proposed new §4.109(a) is basically the same as existing §3.8(d)(1) and specifically identifies prohibited disposal methods. Proposed new §4.109(b), which relates to prohibited recycling methods, imposes a new requirement for obtaining a permit for recycling of oil and gas wastes at a commercial facility unless authorized by other Commission rules.

Proposed new §4.112 (relating to Prohibited Pits) is a slightly modified version of the provisions in existing §3.8(d)(2), and sets out specific requirements and conditions for the use of pits.

Proposed new §4.115 (relating to Authorized Disposal Methods for Certain Wastes) is an amended version of §3.8(d)(3), which relates to authorized disposal methods. Proposed new §4.115(a), an amended version of §3.8(d)(3)(A), authorizes discharge of water condensate to the land surface without a permit if the benzene concentration of the water condensate does not exceed 0.05 milligrams per liter (mg/L) and the chloride concentration does not exceed 500 milligrams per liter (mg/L). Proposed new §4.115(b), an amended version of §3.8(d)(3)(B), prohibits the disposal of inert waste in a permitted pit if the permit does not authorize disposal of inert waste and prohibits disposal of inert waste in a lined pit if the waste could reasonably be expected to damage the liner. In addition, proposed new subsection (b)(4) would prohibit disposal of inert waste by burning if the burning is prohibited by state or county law.

Proposed new §4.115(c), an amended version of §3.8(d)(3)(C), imposes additional conditions on authorized disposal of low chloride water base drilling fluid by landfarming. This subsection would limit to 5.0% the slope of the area to be landfarmed, unless a greater slope has been approved by the Commission. In addition, this proposed new subsection (c) requires that the area where the waste will be landfarmed be at least 100 feet from surface water and that the waste to be landfarmed have a pH of between 6 and 10 Standard Units. Paragraphs (8) and (9) of proposed new §4.115(c) place a limit of four mmhos/cm on the electrical conductivity (EC) and one percent by weight total petroleum hydrocarbon (TPH) concentration, respectively, on the waste/soil mixing after landfarming.

Proposed new §4.115(d), relating to drilling fluid, imposes additional conditions on burial of certain types of drilling fluid, sands, silts, and cuttings than those found in current §3.8(d)(3)(D).

Proposed new §4.115(e), relating to completion/workover pit wastes, is an amended version of §3.8(d)(3)(E) that adds conditions to the burial of completion or workover pit wastes. All of these additional requirements are intended to minimize the likelihood of pollution of surface or subsurface water from such disposal.

Proposed new §4.115(f) relates to the effect on backfilling and is the same as current §3.8(d)(3)(F).

Proposed new §4.115(g) officially authorizes the disposal of oil and gas waste at a facility permitted by another state agency, another state, or the federal government if the waste generator submits to the Commission documentation regarding the shipment of waste to such a facility within 30 days after shipment. The Commission has used this standard informally since 1997 in an effort to streamline disposal requirements. As proposed, this subsection eliminates the need to obtain a minor permit from the Commission for such management while still ensuring that the Commission has the ability to track oil and gas wastes that are managed at facilities other than those permitted by the Commission.

Proposed new §4.115(h) authorizes the disposal of sewage in a manner permitted or authorized by the Texas Natural Resource Conservation Commission (or its successor agency) or the county in which the disposal occurs.

Proposed new §4.115(i), relating to storm water, authorizes disposal of storm water from a firewall by discharge to surface water provided such discharge is authorized by federal law, and authorizes discharge of storm water by discharge to the ground surface under certain conditions.

Proposed new §4.115(j) relates to hydrostatic test water from a new pipeline and authorizes discharge of hydrostatic test water from a new pipeline to the ground surface without a permit under certain conditions.

Proposed new §4.115(k), relating to used oil, is identical to existing §3.8(d)(9), and requires used oil to be managed in accordance with 40 CFR Part 279.

Proposed new §4.115(l) requires that a person maintain for three years documentation of compliance with the section. Documentation is required in any case where a person uses either testing or uses knowledge of processes and the characteristics of the wastes generated by those processes to determine compliance with the section.

Proposed new §4.118 relates to authorized pits. Proposed new subsection (a) is an amended version of current §3.8(d)(4) and requires that rule-authorized pits meet certain general requirements, set out in subsection (b), and certain specific requirements applicable to the specific type of pit, set out in subsection (c).

Proposed new §4.118(b) sets out the general requirements for authorized pits with respect to site restrictions, construction standards (including liner standards), operating standards, and closure standards.

Proposed new §4.118(c)(1) is an amended version of current §3.8(d)(4)(A)(i) and requires that a reserve pit or mud circulation pit be lined if the pit contents have a chloride concentration greater than 6,100 mg/l, if the pit contains oil base mud, if the pit is constructed in alluvium, or if the bottom of the pit is less than 20 feet from the top of the seasonal high water table. In addition, unless the Commission determines a cap is not necessary or the pit is emptied prior to closure, proposed new §4.118(c)(1) requires that a cap be installed over any reserve pit or mud circulation pit that was used to hold oil base mud or drilling fluids with a chloride concentration greater than 3,000 mg/l. In certain areas where the net evaporation rate is much greater than the net precipitation rate and ground water is deep, the proposed rule allows the use of a capillary barrier in lieu of a cap to prevent upward migration or "wicking" of salt constituents.

Proposed new §4.118(c)(2) is an amended version of current §3.8(d)(4)(B), and authorizes completion/workover pits. As proposed, the new provision adds various waste streams that may be placed into an authorized completion/workover pit and requires that the pit be lined.

Proposed new §4.118(c)(3) is an amended version of current §3.8(d)(4)(C) and provides that basic sediment pits may be used only for storage and must be lined, and that any basic sediment pit in use on or after 180 days from the effective date of the new rule be closed or lined.

Proposed new §4.118(c)(4) is an amended version of current §3.8(d)(4)(D). As proposed, the new provision requires that any flare pit, other than a flare pit located and used in conjunction with operations at a well or a tank battery or a flare pit used in conjunction with a continuous-burn flare, be lined, and that the liner must be fireproof if the pit is used in conjunction with a flare. In addition, subsection (c)(4) requires that any flare pit in use on or after 180 days from the effective date of the new rule be closed or lined.

Proposed new §4.118(c)(5), an amended version of current §3.8(d)(4)(E), increases from 120 to 180 days the time within which the pit must be closed.

Proposed new §4.118(c)(6), an amended version of current §3.8(d)(4)(F), requires that all water condensate pits be lined and increases from 120 to 180 days the time within which the pit must be closed. In addition, any water condensate pit in use on or after 180 days from the effective date of the new rule must be closed or lined.

Proposed new §4.118(c)(7) authorizes the use of sumps in compliance with applicable regulations promulgated by the United States Environmental Protection Agency or the United States Department of Transportation. In addition, the use of small sumps, as defined in §4.103, is authorized. Currently, §3.8 is silent on this type of pit, which has caused confusion in the past. These proposed new provisions clearly authorize certain sumps and eliminate the question of whether or not this type of pit is authorized.

The Commission proposes to adopt rules in new Division 3, relating to standards for permits and waste management methods, which are amended versions of current §3.8(d)(6). Among the changes from the current requirements in §3.8(d)(6) is the incorporation of the Commission's current permitting guidelines.

Proposed new §4.121 (relating to General Standards for Permit Issuance) is a reorganized version of current §3.8(d)(6). Proposed new subsection (a) establishes general standards for issuance of a permit. Proposed new subsection (b) is an amended version of current §3.8(d)(6)(A) and sets forth standards for certain unlined pits. Proposed new subsection (c) provides that the term of any permit issued under Subchapter B may be limited subject to renewal. Proposed new subsection (d) is an amended version of current §3.8(d)(7)(A), but does not contain language that pertains to implementation of the 1984 amendments to §3.8 and that is now obsolete. In addition, the Commission is not proposing to adopt in Subchapter 4 the language in current §3.8(d)(8) because this language, relating to existing brine mining pit permits and brine mining pits, is also obsolete. Proposed new subsection (e) authorizes the automatic transfer from one operator to another of a pit permit associated with a particular lease upon Commission approval of the P-4 lease transfer for all pit permits except for those at commercial facilities.

The Commission proposes new §4.124 (relating to Siting Standards for Permit Issuance), which requires that permitted pits and landfarms meet the siting requirements for rule- authorized pits and landfarms, respectively, in addition to other siting restrictions.

Proposed new §4.127 (relating to Closure Standards) is an amended version of current §3.8(d)(6)(D). As proposed, this section requires that permitted pits and landfarms meet the construction standards for rule-authorized pits and or rule- authorized landfarming, respectively, except that where a synthetic liner is used, the thickness must be at least 30 mil (or 60 mil if the liner is made of high density polyethylene.) Proposed new §4.127 also includes other standards that are generally included in the permits that the Commission currently issues under §3.8.

The Commission proposes new §4.130 (relating to Operating Standards for Permitted Pits and Landfarms). This new section requires that permitted pits and landfarms meet the operation standards for rule-authorized pits and landfarms, respectively, and includes certain conditions for operating a pit or landfarm that are currently included in the permits issued under §3.8. Also, this proposed section includes the language from current §3.8(d)(6)(E) authorizing the Commission to impose additional operating conditions under any permit.

Proposed new §4.133 (relating to Closure Standards) is an amended version of current §3.8(d)(6)(F) and requires that all permitted pits used for storage of oil field brines, geothermal resource waters, or other mineralized waters be emptied prior to closure. Proposed new §4.133 includes language from current §3.8(d)(6)(F), which authorizes the Commission to impose additional closure requirements under the permit.

Proposed new §4.136 (relating to Documentation Demonstrating Compliance) requires that a person maintain documentation to demonstrate compliance with the requirements in Division 3.

The Commission proposes to adopt rules in new Division 4 of Subchapter B which govern application requirements for waste management permits.

Proposed new §4.139 (relating to Information Required for Permit Application for a Non-commercial Facility) is an amended version of current §3.8(d)(6)(B) and more clearly details the requirements for general application information and application information on siting, construction, operation, and closure of the proposed pit or landfarm.

The Commission also proposes new §4.142 (relating to Additional Information Required for Permit Application for a Commercial Facility), which lists the information required to be submitted with any permit application for a commercial waste management facility to be permitted under Subchapter B, including requirements that a commercial facility operator comply with the applicable provisions of §3.78(r) (relating to Fees, Performance Bonds and Alternate Forms of Financial Security Required to Be Filed) and notify the Commission if the person is placed into bankruptcy.

The Commission also proposes new §4.145 (relating to Notice, Protests and Hearings) which is an amended version of current §3.8(d)(6)(C) that more clearly delineates the requirements for notice of a permit application under Subchapter B, including additional notice requirements for commercial facilities.

The Commission proposes to adopt rules in new Division 5 of Subchapter B that relate to pollution control for activities on surface waters. The proposed new rules are an amended version of current §3.8(e). The general language of current §3.8(e) was adopted by Commission Order Number 20-59,200, effective May 1, 1969, and was applicable to oil, gas and geothermal activities conducted in "the waters of the Texas offshore and adjacent estuarine zones." Subsequently, Commission Order Number 20- 60214, effective October 1, 1970, made the provisions included in current §3.8(e) "required and enforced as to all oil, gas, or geothermal resource operations conducted on the inland and fresh waters of the State of Texas, such as lakes, rivers, and streams."

Proposed new §4.148 (relating to Applicability) clarifies that the proposed new rules in Division 5 apply to oil and gas exploration, development, and production activities conducted on surface waters in the state, including waters or the Texas offshore and adjacent estuarine zones, lakes, rivers and streams; however, as proposed, this new section does not include language currently in §3.8(e) that appears to authorize discharges of oil and gas wastes, such as produced water and drilling fluids, that are now prohibited by federal law.

The Commission proposes new §§4.151 (relating to Reporting of Surface Water Pollution), 4.154 (relating to Corrective Action), and 4.157 (relating to Suspension of Production) to more clearly organize the corresponding language currently contained in current §3.8(e).

The Commission proposes new rules in new Division 6 of Subchapter B, relating to waste hauling, tracking, and recordkeeping. Proposed new §4.160 (relating to Oil and Gas Waste Haulers) is an amended version of current §3.8(f) that reorganizes for clarity the requirements on applicability, exclusions, permit application requirements, permit conditions, and hauling records. Proposed new §4.160 also makes clear that a permit to haul oil and gas waste does not authorize the permittee to gather oil, gas, or geothermal resources. In addition, the proposed new section excludes from the oil and gas waste hauler permit requirements hauling of oil and gas waste that is NORM, as defined by §3.94 (relating to Disposal of Oil and Gas NORM Waste), and hauling of oil and gas waste to a disposal facility permitted by another state agency, another state, or an agency of the federal government under certain conditions.

Proposed new §4.163 (relating to Waste Tracking and Recordkeeping) is an amended version of current §3.8(g). Proposed new subsection (a) requires that a waste hauler and the operator of an off-site treatment, storage, disposal, or injection facility permitted by the Commission maintain copies of manifests, run tickets, or shipping papers for each load of waste for three years. The manifest, run ticket, or shipping paper must identify the operator, generation site, and county of generation. Proposed new subsection (b) requires that the treatment, storage, disposal, or injection facility operator report significant discrepancies in information contained in the manifest, run ticket, or shipping paper to the Commission and the waste generator.

The Commission proposes new rules in new Division 7 of Subchapter B that govern alternatives, exemptions, and exceptions. Proposed new §4.166 (relating to Alternatives) allows the Commission to approve alternatives to the provisions of Subchapter B, except for those in Division 9, relating to Consistency with the Texas Coastal Management Program, for good cause, if it is demonstrated to the Commission's satisfaction that the alternatives protect public health, safety, and the environment.

Proposed new §4.169 (relating to Emergency Permits) prescribes the requirements for an emergency permit and includes minor amendments to those currently imposed under §3.8(d)(6)(F).

The Commission proposes new §4.172 (relating to Minor Permits), which is an amended version of current §3.8(d)(6(G) that extends the term of a minor permit from 30 days to 60 days.

The Commission proposes new rules in new Division 8, relating to responsibility, compliance, and penalties. Proposed new §4.175 is a slightly amended version of current §3.8(d)(5) and relates to responsibility for waste disposal.

Proposed new §4.178 (relating to Modification, Suspension, and Termination of Permits) is an amended version of current §3.8(d)(E). The proposed new rule adds as good cause for the Commission to modify, suspend or terminate a permit a finding that continued operation of a facility presents an imminent danger to life or property.

The Commission proposes new §4.181 (relating to Penalties) an amended version of current §3.8(h).

The Commission proposes new rules in new Division 9, relating to consistency with the Texas Coastal Management Program. These proposed rules embody a slightly amended version of current §3.8(j). The new rules reorganize §3.8(j) and update the references to the Texas Natural Resource Conservation Commission or its successor agency to reflect the name change of the agency that will be final on September 1, 2004. In addition, the reference to the effective date of the section was updated. The Commission proposes no substantive changes to §3.8(j) in the proposed new rules.

The Commission reviewed the proposed new rules and found that the proposal of new §4.184, (relating to Applicability), §4.187 (relating to Specific Policies), §4.190 (relating to Consistency Determinations), and §4.193 (relating to Thresholds for Referral), all of which will be included in Division 9 (relating to consistency with the Texas Coastal Management Program) is a rulemaking identified in the Coastal Coordination Act Implementation Rules, 31 TAC §505.11(3), and, therefore, will require that applicable goals and policies of the Texas Coastal Management Program (CMP) be considered during the rulemaking process.

In accordance with the regulations of the Coastal Coordination Council, the Commission reviewed the proposed rulemaking for consistency with the CMP goals and policies. The CMP goal applicable to this rulemaking is the goal to protect, preserve, and enhance the diversity, quality, functions, and values of coastal natural resource areas (CNRAs) in accordance with 31 TAC §501.12(1) (relating to Goals). The CMP policies applicable to this rulemaking are 31 TAC §501.14(c)(1)-(3) (relating to Policies for Specific Activities and Coastal Natural Resource Areas). In accordance with §501.14(d)(1), proposed rules require that the disposal of oil and gas waste in the coastal zone shall comply with the policies listed in §501.14(c)(1)(A)-(B). In accordance with §501.14(c)(2), the proposed new rules require that the discharge of oil and gas exploration and production wastewater in the coastal zone complies with the policies listed in §501.14(c)(2)(A)-(C). In accordance with §501.14(c)(3), the proposed new rules require that the Commission shall comply with all policies for CNRAs when issuing permits and adopting rules under Texas Natural Resources Code, Chapter 91, for oil and gas waste, and under Texas Water Code, Chapter 26, and the Texas Natural Resources Code, Chapter 91, for oil and gas wastewater discharges. Further, the proposed new rules require that the Commission comply with the policies in §501.14(h)(2) when issuing certifications under Texas Water Code, Chapter 26, and the Texas Natural Resources Code, Chapter 91, governing certification of compliance with surface water quality standards for federal actions and permits authorizing development affecting critical areas. And finally, the proposed new rules require that the Commission comply with the policies in 31 TAC §501.14(j). The changes proposed to the language of §3.8(j), which rule previously was deemed consistent with the CMP by the Coastal Coordination Council, and which are proposed in new §§4.184, 4.187, 4.190, and 4.193, are not substantive.

The Commission proposes new rules in new Division 10 of Subchapter B that relate to cleanup by the Commission. Proposed new §4.196 (relating to Cleanup by the Commission) prescribes a protocol consistent with Texas Natural Resources Code, §91.113, for environmental cleanups conducted by the Commission. Proposed new §4.196 also provides an opportunity for responsible operators to assume control of a cleanup by the Commission subject to Commission approval.

The Commission finds that a regulatory analysis of a major environmental rule is not required under Texas Government Code, §2001.0225(b), for two reasons. First, the Commission finds that the proposed new rules in Subchapter B are not "major environmental rules" as that term is defined in Texas Government Code, §2001.0225(g)(3); the Commission finds that the amendments do 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. Second, the proposed new rules do not exceed a standard set by federal law not specifically required by state law; do not exceed an express requirement of state law not required by federal law; do 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; and are not proposed solely under the general powers of the agency instead of under a specific state law. The Commission proposes the new rules under the specific authority of Texas Natural Resources Code, §91.101, which provides that, in order to prevent pollution of surface water or subsurface water in the state, the commission shall adopt and enforce rules relating to the discharge, storage, handling, transportation, reclamation, or disposal of oil and gas waste. The Commission does not propose these new rules under its general powers. Nevertheless, even though the Commission finds that Texas Government Code, §2001.0225, does not apply to the proposed new rules, and without conceding that Texas Government Code, §2001.0225, applies to the proposed new rules, the Commission offers the following Draft Impact Analysis, consistent with the provisions in Texas Government Code, §2001.0225.

DRAFT IMPACT ANALYSIS DESCRIBING ANTICIPATED EFFECTS OF PROPOSED NEW 16 TAC CHAPTER FOUR, SUBCHAPTER B

I. Introduction.

The proposed new rules are intended to strengthen requirements for prevention of pollution of surface and subsurface waters; conform the wording of the rules to reflect current Commission practice; incorporate into the rules the separate Commission publication entitled "Questions and Answers to Rule 8," which was developed after §3.8 was substantially amended in 1984; and respond, in part, to recommendations that arose out of a review of Commission regulatory programs conducted by a stakeholder team selected by the Interstate Oil and Gas Compact Commission (IOGCC).

The overall purpose of the proposed rules is to assure that oil field fluids, oil and gas waste, and other substances and materials generated by activities subject to regulation by the Commission do not cause or allow pollution of surface or subsurface water in the state.

Because the issue of whether the Subchapter B proposal is a major environmental rule subject to a Texas Government Code, §2001.0225, regulatory analysis is a matter of legal interpretation subject to legitimate differences in opinion, and not conceding that the proposed rule is a "major environmental rule," the Commission offers the following Draft Impact Analysis consistent with the provisions in Texas Government Code, §2001.0225. Again, the Commission does not concede that the Subchapter B proposal is a major environmental rule as that term is defined in Texas Government Code, §2001.0225; nor does the Commission concede that the language in Texas Government Code, §2001.0225, requires that the Subchapter B proposal undergo a Draft Impact Analysis.

A. Purpose of Draft Impact Analysis.

The purpose of this Draft Impact Analysis to identify for the public and the regulated community the information that has been considered by the Railroad Commission in arriving at the proposed new rules in Chapter 4, Subchapter B, the information that the Commission has determined to be relevant and reliable, and the assumptions and facts on which the agency has relied in making its regulatory decision with respect to the proposed new rules. In making its final regulatory decision, the Commission will assess all information submitted to it, whether quantitative or qualitative, consistent with generally accepted scientific standards, actual data where possible, and assumptions that reflect actual impacts that the regulation is likely to impose.

B. Duty Concerning Oil and Gas Waste and History of Development of Subchapter B.

This section will give a brief overview of the Commission's statutory duty concerning oil field fluids, oil and gas waste, and other substances and materials and provide a brief history of how the Commission came to propose the provisions in Subchapter B.

1. Statutory Authority.

Pursuant to Texas Water Code, §26.131, the Railroad Commission is solely responsible for the control and disposition of waste and the abatement and prevention of pollution of surface and subsurface water resulting from . . . activities regulated by the Commission pursuant to Texas Natural Resources Code, §91.101. Texas Natural Resources Code, §91.101, provides that in order to prevent pollution of surface water or subsurface water in the state, the Commission shall adopt and enforce rules and orders and may issue permits relating to the discharge, storage, handling, transportation, reclamation, or disposal of oil and gas waste as defined in Texas Natural Resources Code, §91.1011, or of any other substance or material associated with any operation or activity regulated by the Commission such as the drilling of exploratory wells and oil and gas wells, production of oil and gas, and the operation, abandonment, and proper plugging of wells subject to the jurisdiction of the Commission.

Texas Natural Resources Code, §91.1011, provides that "oil and gas waste" means waste, including salt water, brine, sludge, drilling mud, and other liquid, semiliquid, or solid waste material, that arises out of or is incidental to the drilling for or producing of oil or gas, including waste arising out of or incidental to:

--drilling of injection water source wells which penetrate the base of useable quality water;

--the drilling of cathodic protection holes associated with the cathodic protection of wells and pipelines subject to the jurisdiction of the Commission;

--gasoline plants, natural gas or natural gas liquids processing plants, pressure maintenance plants, or repressurizing plants;

--underground natural gas storage facility, provided the terms "natural gas" and "storage facility" shall have the meanings set out in Texas Natural Resources Code, §91.173;

--underground hydrocarbon storage facilities, provided the terms "hydrocarbons" and "underground hydrocarbon storage facility" shall have the meanings set out in Texas Natural Resources Code, §91.201; and

--the storage, handling, reclamation, gathering, transportation, or distribution of oil or gas prior to the refining of such oil or prior to the use of such gas in any manufacturing process or as a residential or industrial fuel.

Waste and other substances and materials generated by these activities, and regulated by the Commission as required by the above-referenced statutes, include produced formation water, drilling fluids and drill cuttings, and other associated wastes. Produced water in Texas contains an average chloride content of 50,000 parts per million (ppm). Associated wastes include: completion and workover fluids, such as fracturing fluids, acidizing fluids, produced sand, tubing scale, paraffin, and tank bottoms (basic sediment).

Drilling fluids are a significant component of oil and gas waste. They are primarily water-based mixtures of clays and inert weighting materials with special additives mixed in low concentrations. Formulation of a particular drilling fluid is based on anticipated downhole conditions. Formulations of drilling fluid that is oil- or salt-water based are used in certain regions when drilling deep, high temperature, high pressure, or water-sensitive reservoirs. Chemicals, such as acids (hydrochloric, nitric, sulfuric, hydrofluoric, formic, and acetic acids), bases, salts, lubricants, corrosion inhibitors (which can contain arsenic compounds), viscosofiers, dispersants, fluid loss reducers, flocculents, surfactants, and biocides, may be added to drilling fluid to control specific problems or fluid properties. In addition, the drilling fluid generally becomes contaminated (with formation fluids, including saline produced formation fluids and oil) as it is used.

Drilling fluid wastes typically contain various levels of salts and oil. These wastes may also contain barium and trace levels of other heavy metals (arsenic, cadmium, chromium, mercury, lead and zinc.) However, numerous studies of various waste management practices indicate that the chloride, total dissolved solids, pH, and hydrocarbon contents in drilling waste are the controlling factors for determining how the waste should be stored and disposed of to prevent pollution.

In addition to factors listed above, there are other potential groundwater contaminants that are inherent in oil and gas wastes, including crude oil, volatile hydrocarbons, chemicals used in treating wells, and corrosion inhibitors. All of the above constituents have the potential to contaminate ground water when spilled on the surface or if they migrate to ground water.

The very nature of this category of wastes makes it difficult to estimate the true extent of ground-water contamination. Due to extensive exploration, production, and transportation activities associated with this industry throughout the state and their relationship to the outcrop areas of the state's major and minor aquifers, oil and gas practices have contributed to ground water pollution. Ground water quality has been impacted by past, now prohibited practices; by accidental spills, pipeline leaks; blow outs; and by situations that are noncompliant with Commission regulations. Numerous documented instances where actual pollution occurred can be considered an indicator of the extent of undocumented pollution. See, for example, "Ground Water Quality of Texas, an Overview of Natural and Man-Affected Conditions," Report 89-01, March 1989, Texas Water Commission.

Thus, the Commission is charged with--and indeed is the sole authority for-- assuring the above-referenced activities and substances do not cause or allow pollution of surface and subsurface water in the state. The Commission's primary tool for accomplishing this charge has been §3.8; Subchapter B proposes improvements to the way the Commission implements its charge.

2. History of Development of Subchapter B.

In 1983, the Texas Legislature enacted three major statutes relating to the protection of fresh water from pollution by oil and gas wastes. House Bill 2005 (HB 2005) prohibits the use of a pit for storage or disposal of oilfield brines, geothermal resource water, or other mineralized water unless the pit is permitted by the Commission. However, the Commission may only permit an unlined, continuous use pit if the applicant conclusively shows that no water pollution will result from use of the pit. The bill required that permits issued by the Commission are to be in writing and contain the conditions under which the pit may be operated. HB 2005 directed the Commission to adopt rules relating to lining pits and to draining, cleaning, and closing pits. It also provided for assessment of penalties for violations of the statute or a rule adopted pursuant to the statute.

House Bill 1970 (HB 1970) clarified the Commission's jurisdiction to adopt rules and issue permits relating to the "discharge, storage, handling, transportation, reclamation, or disposal of oil and gas waste." This statute also defined oil and gas wastes as "waste that arises out of or incidental to the drilling for or producing of oil or gas, or waste arising out of or incidental to the underground storage of hydrocarbons."

House Bill 1445 (HB 1445) allowed the Commission to directly assess a penalty for violation of its pollution control rules. The maximum administrative penalty was set at $10,000 per day per violation.

The Commission amended §3.8 in 1983 to reflect these statutory changes. The rule became effective on May 1, 1984. The amendments also reflected concerns raised by the Oil and Gas Division and the public. In 1985, staff of the Oil and Gas Division also drafted and published a guidance document entitled "Water Protection Manual," which included a discussion of the rule, the thought process behind developing the new rule amendments, and general pollution potential of activities the rule regulates. This guidance document included a discussion of pit construction, including lining of pits, in the various areas of the state, taking into account the climate, geology, typical characteristics and volumes of waste, frequency of pit use, depth to ground water, soil conditions and other factors that could impact the potential for pollution from oil and gas waste management. This guidance document was updated and re-published several times over the following years.

In 1992, the Commission's environmental regulatory programs for oil and gas waste management were reviewed by a multi- stakeholder team coordinated by the Interstate Oil and Gas Compact Commission (IOGCC). The review team included representatives from industry, other state regulatory agencies, and environmental/public interest groups. The review was funded by the U.S. Environmental Protection Agency. These "State Reviews" are generally accepted as part of the voluntary program oil and gas producing states follow in order to maintain the RCRA exemption for oil and gas waste and the continued authority of the states to regulate the waste.

Texas' environmental regulatory programs for oil and gas exploration and production activities were reviewed against a set of guidelines, "EPA/IOCC Study of State Regulation of Oil and Gas Exploration and Production Waste," adopted by the IOCC. The document outlining the Review Team's recommendations was published in April of 1993. The Review Team found that the Commission had good regulatory programs, but recommended improvement in some areas. Since 1993, the Commission has addressed most, but not all, of the Review Team's recommendations. Proposed Subchapter B addresses the remaining recommendations as will be discussed in the following paragraphs.

Following up the Review Team's recommendations, and in anticipation of the Commission's next "State Review," in 1995 through 1996, Commission staff drafted proposed amendments to §3.8. This draft was circulated for informal comment in July of 1997. Staff also held a workshop on the proposed amendments in October 1997. Many changes were made to the original draft amendments in response to the comments and subsequent discussions. In December of 1997, the Commission circulated revised drafts of the proposed amendments to the workshop attendees and industry associations for additional review and comment. By June of 1998, the remaining outstanding issues concerned proposed liner requirements for pits that are used in association with drilling, completion, and workover of oil and gas wells. Staff summarized the areas of concern and the alternatives.

In open meeting conference on February 21, 2002, the Commission directed staff of the Oil and Gas Division to hold a series of workshops for informal public comment on the draft proposal (developed in 1997 and 1998) to amend the requirements of §3.8 and readopt them as new rules in new Chapter 4, Subchapter B.

During March 2002, staff conducted workshops in Midland, Wichita Falls, Houston, Kilgore, Austin, and Amarillo. A total of 188 people attended, including 152 representing industry, six representing land and royalty owners, seven with groundwater conservation districts, and 23 who represented a variety of groups or were unaffiliated. At the workshops, staff briefly explained proposed changes to the rules and solicited oral or written comment. Staff received written comments from 120 persons, many of whom were not in attendance at the workshops. In response to comments received at the workshops and in writing, Commission staff made several changes to the draft version of the rules that was discussed at the workshops, as discussed in Section III, part E.

In open meeting conference on May 22, 2002, the Commission voted to publish for a 60-day formal comment period the proposed new rules in Subchapter B.

C. Structure of Draft Impact Analysis

This analysis is divided into two parts: discussion of whether the proposed new rules are "major environmental rules" subject to a regulatory analysis pursuant to Texas Government Code, §2001.0225(g)(3) and §2001.0225(a), respectively, and the draft regulatory analysis consistent with Texas Government Code, §2001.0225(b), (c), and (e).

II. Major Environmental Rule Subject To Regulatory Analysis

A. Whether the Proposed New Rules in Chapter 4, Subchapter B, Are Major Environmental Rules as Defined by Texas Government Code, §2001.0225(g)(3).

The Commission evaluated whether or not the proposed new rules in Subchapter B are "major environmental rules" as defined by Texas Government Code, §2001.0225(g)(3) and determined that they are not "major environmental rules" as that term is defined, primarily because the proposal does 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.

Texas Government Code, §2001.0225(a), specifically states that it applies only to a major environmental rule. Texas Government Code, §2001.0225(g)(3), defines a major environmental rule as "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." Thus, if a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure does 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, it is not required by statute to undergo a Draft Impact Analysis.

With respect to the fiscal impacts of pit liner requirements, the potentially most expensive new requirements in proposed Subchapter B, the question is whether the potential new expenses constitute a material adverse impact. "Material" in this context means that the pit liner expense is such a significant portion of the overall expense of drilling a well or conducting a workover operation that, more likely than not, it would change the decision to drill a well or conduct a workover operation. Using this test, the expenses associated with pit liner requirements are not material.

Evaluating the new testing and sampling requirements of Subchapter B in the same light leads to the same conclusion. In fact, the cumulative impacts of these potential new expenses do not rise to the level of "material" when considered in the context of all expenses associated with exploration and production activities. Reviewing the potential new expenses as a whole, it is more likely than not that the new requirements in Subchapter B will not cause most people who intend to engage in exploration and production activities to change their minds about becoming so engaged.

B. If the Proposed New Rules in Chapter 4, Subchapter B, Were Major Environmental Rules, Whether They Are Legally Subject to the Regulatory Impact Analysis in Accordance With Texas Government Code, §2001.0225(a).

1. Does the rule exceed a standard set by federal law or an express requirement of state law?

No. "Law" is statutory law enacted by Congress or the State Legislature. See, Hearings on Tex. S.B. 633 Before the Senate Committee on Natural Resources , 75th Leg., R.S. (Feb. 25, 1997) (audiotapes available from Senate Staff Services Office); Debate on Tex. S.B. 633 on the Floor of the Senate , 75th Leg., R.S. (Mar. 17, 1997) (audiotapes available from Senate Staff Services Office); Hearings on Tex. S.B. 633 Before the House Committee on Environmental Regulation , 75th Leg., R.S. (April 8, 1997) (audiotapes available from Office of the House Committee Coordinator). The proposed rules do not exceed standards set by any existing federal law or an express requirement of state law. There are currently no specific standards for management of oil and gas exploration and production wastes under the federal Resource Conservation and Recovery Act (RCRA) as amended. The proposed rules are consistent with and do not exceed the general standards established by Congress in RCRA Subtitle D. Although EPA has considered establishing specific requirements for nonhazardous oil and gas wastes under Subtitle D, it has not done so.

The general performance standards present in Subtitle D relate to land disposal of solid wastes. These guidelines and minimum performance standards are not enforceable and only serve as recommendations or suggestions to the state agencies. EPA has generally left regulation of land disposal of oil and gas wastes to the individual states, thus there are very few federal standards the proposed rules could potentially exceed.

In 1980, Congress specifically exempted most oil and gas wastes (produced water, drilling fluid, and associated wastes) from regulation as hazardous wastes under Subtitle C of the Resource Conservation and Recovery Act (RCRA) pending further study by EPA. On July 6, 1988, after conducting the required study, EPA published a regulatory determination on this issue. EPA concluded that: (1) regulation of exempt oil and gas wastes as hazardous wastes is unnecessary and would have severe economic impacts; (2) oil and gas wastes pose no significant threat to public health and the environment when managed in accordance with existing federal and state programs; and (3) existing programs are generally adequate for oil and gas wastes and any needed improvements should begin with these existing programs. During its study, EPA identified some areas where it perceived "gaps" in existing federal or state programs: (1) insufficient controls on landfarming, roadspreading, pit construction and surface water discharge practices; (2) insufficient controls for central disposal and treatment facilities; and (3) no specific controls for the management of associated wastes. To fill these gaps, EPA proposed to: improve federal regulations under existing authorities of Subtitle D of RCRA and other federal environmental laws; work with the states to strengthen state regulations and enforcement; and ask Congress for additional authority, if necessary.

While RCRA Subtitle D does not contain specific guidelines for regulation of exploration and production wastes, it does provide clear statutory authority to do so. EPA has authority under Subtitle D of RCRA to promulgate more tailored criteria for oil and gas wastes. EPA initiated a study of associated wastes shortly after 1988, which may have been a preliminary step towards development of Subtitle D regulations (although not the stated intention of the study). A draft of the report resulting from this study, "Preliminary Investigation of Selected Associated Wastes," was released for review and comment in 1995.

Although EPA has not asked Congress for any additional authority to date, the issue of regulation of exempt oil and gas wastes was a key issue in the Congressional debate on RCRA reauthorization in 1991. The Senate Subcommittee on Environmental Protection and the House Subcommittee on Transportation and Hazardous Materials held hearings in September of 1991 on the issue of exempt oil and gas wastes. After the hearings in September of 1991, interested members of the House subcommittee attempted to negotiate an agreement on the oil and gas waste issue. The discussion centered around how, not whether, to regulate exempt oil and gas wastes under RCRA. One proposal involved lifting the exemption for associated wastes and requiring state programs for produced water and drilling fluids to meet stringent standards similar to hazardous waste management standards. Another proposal attempted to provide for some federal oversight without disrupting existing state programs. This proposal retained the exemption for oil and gas wastes and adopted the IOGCC criteria as federal standards for state programs. The House subcommittee did not succeed in reaching a consensus and Congress has not resolved the extremely controversial oil and gas waste issue, nor has it passed any RCRA reauthorization legislation. However, this issue is likely to be key in the discussions when Congress again takes up RCRA reauthorization.

Since 1988, EPA and the states have been working to improve state regulations and enforcement. In January of 1989, the states and EPA, through the Interstate Oil and Gas Compact Commission (IOGCC), developed a report to focus on the elements necessary for an effective state regulatory program, with advice from representatives of industry and environmental groups. The initial report was released in December of 1990. With funding from EPA, a stakeholder committee, the State Review Committee, began coordinating a state review project where individual state regulatory programs are compared with the IOGCC report. Most of the major oil and gas producing states have been reviewed. Today, this process continues under a new, independent governing body, named State Review of Oil and Natural Gas Environmental Regulations (STRONGER). STRONGER is an independent non-profit 501(c)(3) corporation with board comprised of equal representation of representatives from state regulatory bodies, industry, and public interest/environmental groups.

Both EPA and the states recognize that the factors supporting the exemption are still valid--that unnecessary, overly stringent, inflexible federal regulation would result in severe economic hardship to the point that significant production would no longer be viable. Existing state and federal regulatory programs are still generally adequate for controlling exploration and production wastes, and those programs are continually improving, in part as a result of the state review process. The state has been regulating wastes for a much longer period than has EPA. Continued participation in the state review process is an important step in ensuring that regulation of exploration and production wastes is left to the state.

Standards under other federal law that may apply are not exceeded by the provisions in proposed Subchapter B. For example, standards in the federal National Pollutant Discharge Elimination System (NPDES) Program under the federal Clean Water Act are not exceeded, nor are standards in the Coastal Zone Management Act. The proposed rules are consistent with standards for management of used lubricating oil, which appear in 40 CFR 279.

The proposed rules are consistent with standards in other Texas law. For example, the proposed regulations are consistent with Texas Department of Health regulations for management of Naturally Occurring Radioactive Material (NORM) waste, and TNRCC and/or county regulations for management of sewage waste, and do not exceed these standards. Because the Commission is "solely responsible" for managing oil and gas waste, there is little to no likelihood the proposed rules exceed a standard of state law.

2. Does the rule exceed a requirement of a delegation agreement or contract between the state and an agency or representative of federal government to implement a state and federal program?

No. As noted above, EPA has not developed specific standards for oil and gas wastes under RCRA Subtitle D. The programs under the proposed rules include no federally delegable programs, other than the federal NPDES program under the Clean Water Act. The Commission has not been delegated authority for the NPDES program.

3. Is the rule adopted solely under the Commission's general powers?

No. The Commission is proposing the rules under the specific authority of Texas Natural Resources Code, §91.101, which provides that, in order to prevent pollution of surface water or subsurface water in the state, the Commission shall adopt and enforce rules relating to the discharge, storage, handling, transportation, reclamation, or disposal of oil and gas waste.

In addition, the Commission proposes the new rules under Texas Natural Resources Code, §81.052, which authorizes it to adopt necessary rules and regulations for governing persons and their operations involving oil and gas wells and pipelines; Texas Natural Resources Code, §85.042(b), which authorizes the Commission to adopt rules for the prevention of operations in the field dangerous to life or property; Texas Natural Resources Code, §91.109, which authorizes the Commission to require performance bonds or other forms of financial security from a person permitted to manage oil and gas waste; Texas Natural Resources Code, §91.113, which authorizes the Commission to conduct environmental assessments and to control and clean up pollution; Texas Natural Resources Code, §91.455, which authorizes the Commission to adopt rules relating to saltwater disposal pits and to authorize use of such pits; Texas Water Code, §26.131, which provides that the Commission is solely responsible for control and disposition of oil and gas waste and the prevention of pollution of surface water resulting from oil and gas exploration, development, and production operations, and which authorizes the Commission to issue permits for the discharge of oil and gas waste to surface waters; Texas Water Code, Chapter 29, which authorizes the Commission to regulate oil and gas waste haulers; and Texas Health and Safety Code, §401.415, which authorizes the Commission to regulate disposal of oil and gas NORM waste.

For the foregoing reasons, the proposed new rules in Subchapter B are not major environmental rules as defined by Texas Government Code, §2001.0225(g)(3), and if they were, they are not legally subject to a draft or final regulatory impact analysis under the provisions of Texas Government Code, §2001.0225(a).

III. Draft Impact Analysis Describing Anticipated Effects of Proposed Subchapter B.

A. Problems Proposed New Subchapter B Is Intended To Address.

These proposed new rules are generally consistent with current Commission practices. The Commission finds that they are necessary to meet the existing "no pollution" standard in §3.8(b) and proposed to be re-adopted in new §4.101. The proposed new rules are intended to incorporate into the rules the separate publication entitled "Questions and Answers to Rule 8," which was developed after §3.8 was substantially amended in 1984: strengthen requirements for prevention of pollution of surface and subsurface waters; respond, in part, to recommendations that arose out of the review of the Commission's environmental regulatory programs by a multi-stakeholder team; and conform the requirements of the rule to other state and federal requirements. The proposed new rules specifically:

1. Strengthen requirements for the prevention of pollution of surface and subsurface waters.

Changes from current §3.8 reflect the experience of the Commission in trying to implement and enforce the rules over the past 18 years. A primary need that has come to the Commission's attention is clarification, for the benefit of the public and the regulated industry, of what the Commission requires as necessary to meet the performance standard of "no pollution." Further, this clarification of the standards is expected to enhance the ability of the Commission to enforce the rules.

2. Conform the wording of the rules to reflect current Commission practice.

The proposed rules would authorize by rule certain cost- cutting measures that were adopted by the Commission and are outlined in an August 1998 Notice to Operators on Environmental Regulatory Cost-Cutting Measures. The Commission adopted several measures to provide some relief to industry during this period of low oil and gas prices. The measures allowed operators to cut business costs by reducing the time and paperwork required for compliance with certain environmental regulations while still maintaining environmental standards. The measures include:

--Automatically transferring a non-commercial pit permit from one operator to another with an approved P-4 change of operator filing;

--Lengthening the term of a minor permit from 30 days to 60 days; and

--Eliminating the requirement for a minor permit in certain situations, such as for disposal of oil and gas waste at a facility licensed or permitted by another state agency, another state, or the federal government.

Further, the Commission has developed general "rules of thumb" as a result of certain situations that have arisen since the 1984 amendments to §3.8. These include certain situations, such as construction and use of a pit over an alluvial aquifer, where the district directors have determined that liners are required to prevent pollution. Where these "rules of thumb" establish standards generally applicable to persons under Commission jurisdiction, the standards are required to be in the rules.

In addition, there are areas where the current rule is not clear to operators, Commission staff, or the public. These areas have resulted in unintended violations by an operators who interpreted the rule differently from the Commission. These areas have also resulted in difficulty in Commission enforcement of the rule. The proposed new rules are an attempt to address these areas and make them clearer to all. Some of these areas include disposal of certain wastes (sewage, water condensate, storm water), pit liner requirements to prevent pollution of surface and subsurface water, and appropriate siting, construction, operation, and closure standards.

3. Incorporate into the rules the separate publication entitled "Questions and Answers to Rule 8," which was developed after §3.8 was substantially amended in 1984.

The Commission proposes to incorporate elements from this document into new Subchapter B. For example, question number 6 in the "Questions and Answers to Rule 8" concerned whether or not a "bell hole," which is constructed to allow repair of pipeline leaks, is a "pit" within the meaning of §3.8. Because such a hole is emptied and backfilled immediately, it is not a "pit." This clarification is evident in the definition of "bell hole" in proposed new §4.103(5).

Question number 10 concerned whether or not a sump that is used to collect various types of oily wastes is a "pit" within the meaning of §3.8. A sump, which (1) has a capacity of 500 gallons or less; (2) is constructed of concrete, steel, or fiberglass; and (3) is used to collect: (a) lube oil or antifreeze from machinery; (b) glycol from a dehydration system; (c) pigging liquids at a pig trap, or (d) fresh hose-down water, is not a "pit" requiring a permit under §3.8, regardless of whether the sump is an enclosed vessel or open to the atmosphere, provided that the material collected in the sump is removed from the sump within a reasonable period of time. The Commission is proposing to incorporate this "authorization" into proposed new §§4.103(52) and 4.118.

Question number 16 concerned whether or not a "pit" is also a "flare pit" if it only contains a vent line for venting rather than flaring gas. Subchapter B answers this question in the affirmative; this clarification is incorporated in the definition of "flare pit" in proposed new §4.103(26).

4. The proposed rules respond, in part, to recommendations that arose out of the 1992 IOGCC State Review.

As discussed in previous sections, the Review Team's Report outlining its recommendations was published in April of 1993. With respect to surface waste management, the Review Team recommendations addressed in the proposed rules are as follows:

--Keep records of all pit locations and make available to the public.

--Allow staff to periodically compile, publish, update in- house technical criteria.

--Continue broad enforcement/liberal application of §3.8(b), until specific site restrictions/prohibitions are developed and implemented.

--Consider site suitability for all minor permit applications requesting authorization for waste disposal or storage at sites that are not already permitted for this activity.

--Periodically evaluate rule-authorized waste management practices in §3.8 to determine whether a minor or individual permit should be required for certain practices.

--Evaluate whether 15-day notice provides adequate opportunity for citizen participation in permitting decisions and whether an opportunity to comment should be required for certain minor permit applications.

--Issue permits for disposal of drilling fluids in municipal landfills only if a better option is not available.

For authorized pits, the Review Team Report included the following recommendations: (1) revise §3.8 to include requirements applicable to authorized pits based on specific geologic, topographic, hydrologic, or other conditions; (2) require prior notice of construction and use of authorized pits; (3) prohibit the use of unlined basic sediment pits for the disposal of oily wastes; (4) develop rules specifying site restrictions, prohibitions, construction notice requirements for the various types of authorized pits; and (5) amend §3.8 to define minimum construction standards for all rule-authorized pits, to include general operating standards for rule-authorized pits, and to add general pit closure standards for rule- authorized pits.

For pit permits, the Review Team Report included the following recommendations: (1) amend §3.8 regulatory standards for permits to specify that: pit size should be sufficient to ensure adequate storage until closure, taking into account historical precipitation patterns; pit depth should be such that the bottom does not penetrate groundwater, or such that pit contents do not adversely impact groundwater or surface water; and berm height, slope, and material should be such that the pit is structurally sound, and that pit integrity is not compromised by terrain or breached by heavy rains, winds, seepage or other natural forces; (2) impose a fixed term limit on all individual pit permits; (3) amend §3.8 to include specifications for site restrictions for various types of permitted waste management facilities, to include general operating standards for permitted pits, and to add general pit closure standards for permitted pits.

For land treatment and road spreading, the Review Team Report included the following recommendations: (1) publish a guideline document for land treatment, including current "rules of thumb" standards and considering amendment of §3.8 to include minimum operational requirements for land treatment; and (2) adopt minimum regulatory requirements for road spreading and publishing guidelines for application.

For commercial and large centralized facilities, the team recommended that the Commission: (1) continue to require construction, operating, and closure plans for commercial/centralized facilities (2) require a siting plan for these facilities; (3) amend rules to reflect the requirement that applicants provide written notice to adjacent landowners of permit applications for commercial/centralized facilities; (4) impose permit term limits for pits associated w/commercial/centralized facilities and municipal landfills; (5) specify, by rule, construction, maintenance, operation, and closure requirements for commercial facilities; and (6) review permits for commercial and centralized disposal facilities at least once every five years.

For waste tracking, the team recommended that the Commission: (1) finalize development of a three-part form to track waste and require form retention for three years; (2) make part of the form an attest to no illegal dumping; and (3) develop a discrepancy reporting requirement.

5. The proposed rules better conform the existing regulatory requirements with other state and federal requirements.

The proposed new rules delete language concerning discharge of drilling fluids and produced water to surface waters of the state because such discharges are now prohibited by federal law under the National Pollutant Discharge Elimination System (NPDES) program. The proposed new rules authorize other discharges that are also authorized by a general permit or individual permit under the federal NPDES program to eliminate some duplication. Under the proposed rules, the management of used lubricating oil would be conformed to the federal requirements. The proposed new rules also authorize certain sumps that are currently authorized under the federal used oil regulations found in 40 CFR 279.

Current §3.8 is silent on management of certain oil and gas wastes, such as sewage and storm water. Technically under the current rule an operator would be required to get a permit to dispose of such wastes; however, the Commission has received very few applications for such permits. The proposed new rules authorize management of such wastes under certain conditions so that a permit is not required. To avoid duplication, the proposed new rules authorize disposal of sewage in accordance with regulations that already exist under the TNRCC or county health departments.

B. Whether Rules in Proposed Subchapter B Are Necessary To Address the Problems.

The Administrative Procedure Act defines a rule as "a state agency statement of general applicability that implements, interprets, or prescribes law or policy; or describes the procedure or practice requirements of a state agency." Texas Government Code, §2001.003(6). The legislature has delegated rulemaking authority to agencies in order to secure expert action on important, complex, uncertain, and controversial policy matters. Agency rulemaking power is a delegated one; the delegation includes not only a definition of the areas in which an agency may make rules but also a statement of the procedural requirements that the exercise of that power requires. Through the Administrative Procedure Act, the legislature mandated the use of "notice and comment" rulemaking procedures for agency rules.

The agency must give public notice of its proposed rules and the legal and factual bases of those rules to provide a reasonable opportunity for all interested persons to comment; thus there is a clear legislative determination that interested persons --not just affected persons --are entitled to know the agency's rationale for the originally proposed rule. Following receipt of comments, the agency is obliged to consider fully the legal, factual, and policy-related issues raised by the rule, especially in the comments; the agency is obligated to evaluate such data and arguments in order to decide whether the proposed rule will be adopted verbatim, modified, or rejected in its entirety. The agency must write in its final order adopting the rule a reasoned justification that openly and adequately explains the agency's real reasons for the choices it makes.

The Commission has been charged by the legislature with the duty of establishing the specific standards and requirements that operators must meet under the general statutory mandate not to pollute surface and subsurface water. Therefore, when the Commission determines what actions an operator must take in order to prevent the pollution of surface and subsurface waters, it is not only appropriate but necessary that the Commission do so through the prescribed procedures for rulemaking. The rulemaking procedures secure two important goals: first, public notice of the proposed rules--that is, the statements of general applicability that implement the statutory mandate not to pollute and that prescribe the agency's policy with respect to the manner and method of operator compliance--and second, a meaningful opportunity for interested persons to participate in the development of those rules. In addition, the very fact of having the agency's policy set forth in rules means that these statements are available not only to the regulated industry, but to the public in whose interest the Commission regulates that industry.

C. Benefits the Railroad Commission Anticipates From Adoption and Implementation of Proposed Subchapter B, Including Reduced Risk to Human Health, Safety, and the Environment.

Benefits the Commission anticipates from adoption and implementation of proposed Subchapter B are reduced risk to surface and subsurface waters of Texas, a clearer statement of standards expected from the regulated community, and reduced pollution clean up costs in the future. A collateral benefit will be Texas putting itself in a position to undergo its followup state review, and updating its regulatory scheme so it is consistent with neighboring producing states, reinforcing the state's position as primary regulator of oil and gas waste management . Finally, the proposed rules for the most part address and resolve the problems referenced Section III. A. above.

Groundwater is vulnerable to contamination from oil field activity. It is the most likely resource to experience a pollution problem from unlined pits. In Texas, all nine major aquifers and 20 minor aquifers have experienced some form of contamination. Clean ground water is needed for drinking, agriculture, and industry. Poor or contaminated ground water can severely impact crops and threaten the health of livestock. Groundwater contamination has become a growing concern in recent decades as needs increase and we have learned how our activities impact water quality.

Texas has been producing oil for more than 100 years. Prior to 1969, the state allowed disposal of saline produced waters in surface pits and surface waters of the state. It is difficult to ascertain just how much ground water contamination resulted from pre-1969 produced water management practices, and how much can be attributed to other oil field activities.

There have been damage cases and complaints concerning improper management of reserve pits and completion/workover pits; however, existing rules do not require any ground water quality monitoring with respect to individual authorized pits. The magnitude of the amount of these wastes managed each year in Texas, combined with the typical waste characteristics and the general knowledge that a fluid placed in an unlined pit constructed in permeable soil in an area where there is a migratory path to ground water is likely to result in contamination of that ground water, gives an indication of the cumulative potential for pollution that could be caused by these wastes if managed in unlined pits.

Proposed new rules in Subchapter B regarding the lining of reserve pits and workover/completion pits are the Commission's statement of minimum requirements generally applicable for meeting the current "no pollution" performance standard in §3.8(b). These requirements are consistent with what the more responsible companies in the oil and gas industry have already been implementing as best management practices.

The incremental costs that could be imposed as a result of any additional requirements in proposed Subchapter B would be more than balanced by the benefit to the environment in the form of enhanced protection of surface and subsurface water, as well as the benefit to the regulated community and the public in clarification of what is required to meet the existing "no pollution" performance measure.

D. Quantitative and Qualitative Description of Costs the Railroad Commission Anticipates From Implementation of Proposed Subchapter B.

1. To State Agencies.

The Commission does not anticipate significant costs to state agencies from implementation of proposed Subchapter B.

2. To Local Governments.

The Commission does not anticipate significant costs to local governments from implementation of proposed Subchapter B.

3. To the Public.

The Commission does not anticipate significant costs to the public from implementation of proposed Subchapter B.

4. To the Regulated Community.

Proposed Subchapter B includes provisions that both increase and decrease the regulatory cost. A reduction in regulatory costs will accrue because certain procedures that currently require a permit would be authorized by rule as proposed. Significant cost savings will result as a result of allowing authorized disposal of storm water and hydrostatic test waters from new pipe. In addition, the new definition of "bell hole" clarifies that such a hole is not a pit and a permit for its construction, operation, and closure is not required. The estimated savings in avoiding the cost of obtaining a permit is $500 per permit.

New regulatory costs will accrue as a result of the proposed new rules. These costs are concentrated in four general areas: (1) analytical costs; (2) lining costs; and (3) siting restrictions; and (4) landowner consent.

Analysis of the costs and benefits of proposed Subchapter B is based on data and methods presented in the following Tables 1, 2, 3, 4, and 5. Primary costs that were tabulated include the cost of pollution (Table 1) and compliance costs related to proposed Subchapter B (Tables 2, 3, 4, and 5). Examples of incremental new costs include costs to line certain exploration and production pits (Tables 2, 3, and 4) and new analytical costs (Table 5).

Figure 1: 16 TAC Chapter 4, Subchapter B-Preamble

Figure 2: 16 TAC Chapter 4, Subchapter B-Preamble

Figure 3: 16 TAC Chapter 4, Subchapter B-Preamble

Figure 4: 16 TAC Chapter 4, Subchapter B-Preamble

Figure 5: 16 TAC Chapter 4, Subchapter B-Preamble

Table 1

Table 1 lists expenditures by the State of Texas in Fiscal Year 2001 related to remediation of sites of oil field pollution. Proposed new rules in Subchapter B are designed to reduce such cleanup expenses. One area of significant impact would be in the cleanup of pollution from authorized pits. Although pollution incidents from authorized pits are relatively rare, well- documented cases involving pollution for other types of pits have required state-funded cleanup actions. Because of the typically large size, permitted pits and produced water pits have historically been associated with significant pollution threats. Similarly, it has been argued that the relatively small size of reserve and workover pits will make it difficult to evaluate the pollution threat. However, because the production pits are both numerous and widespread their pollution threat is volumetrically significant.

Cleanup costs in Fiscal Year 2001 totaled $1,245,849 for cleanups that involved pits as well as other environmental problems. Cleanup expenses involving pits represented 19% of statewide oil and gas cleanup costs for Fiscal Year 2001.

Table 2

Table 2 identifies drilling and operating costs and incremental costs expected to result from proposed new rules in Subchapter B. Expenses for drilling are expected to increase by 0.25% as a result of the proposed new rules. Operating expenses are expected to increase by 0.36% as a result of the proposed new rules.

Table 3

Table 3 identifies the inferred expenses to line reserve pit and completion/workover pits. Several variables lower the incremental costs associated with complying with the new lining requirements for pits. Operators currently line a percentage of pits. Not all pits will be required to be lined. Lower cost lining options will be available to many operators. The incremental cost to line a reserve pit is estimated to be $1420. The incremental cost to line a completion/workover pit is estimated to be $85.

Table 4

Table 4 lists the installation costs for lining reserve pits and completion/workover pits with a 12 mil liner.

Table 5

Table 5 lists contracted costs to perform certain analytical procedures as required by the proposed new rules in Subchapter B.

a. Analytical Costs.

Proposed new §4.115(a) authorizes discharge of water condensate and §4.115(i) authorizes discharge of storm water. Discharge is authorized if the fluids meet analytical standards for benzene and chlorides. Under existing §3.8, the same analyses were required to obtain a permit for stormwater discharges. Because the proposed rule eliminates the current requirement to obtain a permit for storm water discharges, the Commission anticipates a net savings. The analytical costs for benzene and chloride analysis are estimated to be $37 on the basis of contract costs paid by the Commission in 2001 and 2002. (See Table 5, Analytical Costs).

Proposed new §4.115(d) authorized landfarming of low chloride drilling fluid if the fluids meet analytical standards for chlorides, total petroleum hydrocarbons (TPH), degree of acidity (pH), and electroconductivity (EC). Increased analytical costs are estimated to be $65 on the basis of similar costs paid by the Commission. (See Table 5.)

Proposed new §4.118(b)(4)(B) describes closure standards for authorized pits if the wastes meet analytical standards for TPH, pH, and benzene. The analytical costs for TPH and benzene and are estimated to be $81 on the basis of similar costs paid by the Commission. (See Table 5).

b. Lining Costs.

The Commission calculated both average pit lining costs (Table 4) and incremental lining costs (Table 3). Incremental lining costs are those extra expenses that accrue to oil and gas operators as a result of proposed new Subchapter B. Incremental lining costs are reduced by several factors including: (1) operators currently line a significant percentage of pits; (2) not all pits will be required to be lined; and (3) lower cost lining options will be available to many operators. Based on assumptions and cost factors tabulated in Part G of this draft analysis, Data and Methodology Used in Performing Analysis, incremental costs would be $1,423 for lining (using a 12 mil liner) a reserve pit and $85 for lining (using a 12 mil liner) a completion/workover pit. These cost increases are relatively small when compared with the total cost of drilling and operating oil and gas wells. The cost of drilling an average well is expected to increase by 0.25% as a result of proposed new analytical and lining expenses (Table 2). The cost of operating an oil well is expected to increase by 0.36% as a result of proposed new analytical and lining expenses (Table 2).

Despite the proposed increase in lining costs, a net savings is anticipated as a result of reduction of costs related to pollution remediation costs (Table 1).

The costs of lining focused exclusively on reserve pits and completion/workover pits. The expense of lining other pits that would be required to be lined, such as basic sediment pits, would be small compared to the expense of lining reserve and completion pits. The American Petroleum Institute (API) supplied information on drilling costs (API, 1998) and Energy Information Agency supplied data on operating costs (EIA, 2000).

Reserve Pits

Six vendors and manufactures of pit liners supplied liner costs. Costs to line a drilling reserve pit with a 12 mil synthetic liner range from $0.13 to $0.20 per square foot, and average $0.182 per square foot. In Texas, the average well is 5000 to 7500 feet deep (API, 1998) and would require a drilling reserve pit of 15,000 square feet. (Data supplied by Commission District Directors). The average sized reserve pit would cost $2721 to line with 12-mil synthetic liner.

Several variables lower the incremental costs associated with complying with the proposed lining requirements for reserve pits. Operators currently line a significant percentage of pits. Not all pits will be required to be lined. Lower cost lining options will be available to many operators. The Commission District Directors estimate that currently operators line approximately 27% of the drilling pits or use enclosed tanks instead of pits. Lining of reserve pits is typically required in Districts 8/8A, and in District 3 reserve pits are replaced by enclosed tanks in order to retain the expensive oil-based drilling fluid. In addition, the proposed rule would not require all reserve pits to be lined with a synthetic liner. Such options include using natural materials.

The Commission estimates that 15% of the pits will not need to be lined because the natural substrate is sufficiently impermeable or the material in the pit is water- based drilling fluid with low chlorides, or current practice uses enclosed tanks. The Commission estimates that 30% of the pits will use local natural materials and such materials will reduce the cost of using a synthetic liner by 50%. Based on those assumptions the average incremental cost to line reserve pits would be $1420 per pit.

According to API, the average 1997 cost to drill a well in Texas was $610,000. This average includes oil wells ($371,000), gas wells ($942,000) and dry holes ($501,000). The costs associated with lining reserve pits would increase these average drilling costs by 0.25%.

Workover/Completion Pits

Typical costs to line a completion/workover pit with a 12-mil synthetic liner are estimated to range from $75 to $500. Based on current experience and because completion/workover pits are small (10 feet by 20 feet), the Commission District Directors estimate that most operators (80%) would self-install the liner for material costs of approximately $75. A typical turnkey contract for lining a completion/workover pit averages $500. Based on more than 200,000 active wells, the Commission estimates that approximately 109,000 workover pits are used annually (one workover every two years).

Several variables lower the incremental costs associated with complying with the proposed new lining requirements for completion/workover pits. Operators currently line a percentage of pits. Not all pits will be required to be lined. Lower cost lining options will be available to many operators. Although lower cost options may be available to operators, the percentage of pits that would take advantage of the lower cost option was not calculated, thus the incremental costs for lining completion/workover pits would likely be smaller.

The Commission District Directors estimate that approximately 17% of the completion/workover pits are currently being constructed with liners or use enclosed tanks instead of pits. In Districts 8/8A, approximately 25% of the completion workover pits are lined. The Commission estimates that 30% of the completion/workover pits would not need to be lined because they would be operated and closed within seven days or because the natural substrate is sufficiently impermeable. The Commission estimated the remaining 70% percent of the completion/workover pits would be lined with a 12 mil synthetic liner. The cost to line the average completion/workover pit is estimated to be $160 per pit ((0.8 x $75) + (0.2 x $500)). The average incremental cost to line completion/workover pits would be $85 per pit.

The EIA (EIA, 2000) has calculated cost indices for secondary oil recovery operations in West Texas. Costs averaged $585,400 for a ten-well lease in 1999. Based on five wells needing lined completion/workover pits on an annual basis, the incremental increased average annual operating cost to line workover pits is $425 or 0.07%.

c. Siting Restrictions.

Proposed new siting restrictions limit the siting of authorized pits within 150 feet of a water well and authorized landfarms within 100 of surface water. In addition, authorized pits may not be located on a barrier island or a beach or in the bed of an intermittent stream. The regulatory cost inherent in these siting restrictions is difficult to quantify. The Commission has not been able to quantify the area in which a pit or landfarm would not be allowed under the proposed minimum distances from water wells and/or surface water. The Commission has no information that pits are located on barrier islands, beaches, or streams; thus the cost to comply with the requirement should be zero; however, pollution has resulted from the siting of pits in such locations in the past.

d. Landowner Consent.

Proposed new §4.115(i), relating to authorized discharge of storm water, also includes provisions requiring an operator to obtain surface owner consent before discharging storm water to the surface. Proposed new §4.115(j), relating to authorized discharge of hydrostatic test water from new pipe outside the pipeline right of way, also requires an operator to obtain surface owner permission. Currently, §3.8 does not specifically require surface owner permission under these circumstances.

The proposed rule requirements may result in additional compensation to surface owners which, in the absence of such provisions, may have been avoided. It is difficult to estimate these costs because of the many variables concerning discharges and operator/surface-owner relations.

e. Cost of Pollution.

Groundwater is the most likely resource to experience a pollution problem from unlined pits. The Commission's experience has been that the cost of remediating contaminated groundwater is either extremely high or technically impracticable in most cases. Although pollution incidents attributable to authorized pits are relatively undocumented, reserve and workover pits are numerous and widespread, and the liquid portion of the pit contents is high in chlorides and TPH. Further, the Commission is handling numerous cases involving pollution attributable to other types of pits. Thus, the increasingly precious nature of groundwater, the direct pollution threat contaminants in pits pose to groundwater, the large number of authorized pits, the high cost or impossibility of cleanup, and the documented history of groundwater contamination attributable to other pits have all been factors in the Commission's decision to propose rules implementing more specific standards for authorized pit operation and closure. The Commission anticipates the proposed regulations will have a net effect of reducing the cost of pollution in the oil field.

Table 1 summarizes state-funded cleanup expenses for Fiscal Year 2001. Pit cleanup costs in Fiscal Year 2001 are included in total cleanup costs of $1,245,849. Thus, approximately 19% of statewide cleanup costs involve pits.

E. Reasonable Alternative Methods for Achieving the Purposes of the Proposed Subchapter B and Reasons the Commission Rejected the Alternatives.

Approximately nine subjects within proposed Subchapter B generated vigorous discussion and prompted the Commission to consider alternative methods.

One issue raised at the workshops and in written comments concerned authorized discharge to ground surface of storm water and hydrostatic test water from new pipe. Draft proposed Subchapter B requires surface owner permission and limits chlorides to 500 mg/l and benzene to 0.050 mg/l. Current §3.8 does not authorize discharge of hydrostatic test water or storm water. The proposal to require written permission of the surface owner for land surface discharge is consistent with a similar requirement for on-site landfarming of low chloride water base drilling fluid. For discharge of storm water from a firewall, the proposed new rules make no change to draft version's requirement for surface owner permission. For discharge of hydrostatic test water, the proposed new rules clarify that written surface owner permission is only required if the discharge is not limited to the pipeline easement or right-of- way.

A second general issue concerned siting restrictions for authorized pits. The February 28, 2002, draft of proposed new Subchapter B would have required that an authorized pit be located no closer than 500 feet from water wells. Current §3.8 does not contain distance restrictions. Commenters asserted that recent city ordinances do not require such distances. One commenter advised that easements for public water supply wells range from 150 to 500 feet. In the proposed new rules, the distance required between an authorized pit and water wells has been reduced from 500 feet to 150 feet.

A third issue concerned siting restrictions for authorized landfarming of low chloride, water base drilling fluid from a reserve pit. The proposed new rules in Subchapter B would prohibit landfarming within 500 feet of surface water and would require that the slope of the land to be landfarmed not exceed 5%. Current §3.8 requires that landfarming be performed such that runoff cannot occur, but contains no specific restrictions with respect to distance from surface water or slope. Commenters asserted that a distance of 500 feet from surface water is not possible in Houston and Kilgore districts. The Commission agreed and changed the distance to 100 feet from surface water. The Commission finds that a limit on slope of land to be landfarmed is necessary to ensure that the drilling fluid will not runoff onto adjacent property and/or into surface water and, therefore, did not change the proposed slope restriction.

A fourth issue concerned lining of certain authorized pits. The version of proposed draft Subchapter B discussed at the workshop would have required a liner for any reserve pit that contains oil based mud, has chloride content of greater than 6100 mg/l, is on alluvium, or is located where ground water is less than 20 feet from the surface. Current §3.8 contains no specific liner requirements but requires that any authorized pit be constructed and operated such that there is no pollution. Commenters asserted that in-situ substratum in many areas would meet liner requirements. Other commenters asserted that the chloride concentration in a reserve pit that would require a liner should be lowered to 3000 mg/l.

The Commission proposed liner requirements for certain reserve pits as a result of factors such as permeability of soil, type of waste, and length of time fluids remain in the pit. The proposed new rules in Subchapter B would allow either an artificial (plastic) or constructed-earthen liner. After reviewing all the comments concerning this issue, the Commission decided to propose allowing either artificial (plastic) or constructed-earthen liner for those reserve pits proposed to require a liner, unless the in-situ substratum meets the hydraulic conductivity of 1 x 10 ^-7 cm/sec. Further, the Commission lowered the proposed chloride limit for unlined reserve pits to 3000 mg/l because of the threat to posed by higher concentrations of chlorides.

The version of proposed Subchapter B discussed at the workshops would have required an artificial liner all completion/workover pits. Current §3.8 does not contain specific liner requirements, but prohibits pollution from the use and closure of such pits. Commenters asserted that many completion/workover pits are used, dewatered, and backfilled in two to five days (Wichita Falls). Commenters further asserted that the reuse of completion/workover pit locations would destroy the artificial liner and create liner debris at the surface. After reviewing all comments concerning this issue, the Commission decided to change the language to require either an artificial (plastic) or constructed-earthen liner, unless in-situ substratum meets hydraulic conductivity of 1 x 10-7 cm/sec or if a completion/workover pit is used, dewatered, and backfilled within a time period of no greater than seven days and it is not in alluvium over a water table greater than 20 feet.

There was much discussion about liner standards. Proposed new Subchapter B would require that an artificial liner be at least 12 mil in thickness and a constructed- earthen liner at least two feet in thickness, placed in six inch lifts and compacted. Current §3.8 contains no specific liner specifications or requirements. Commenters asserted that artificial liners are unwieldy and costly and that operators generally use liner in the field with thickness of between six and ten mils. The Commission made no change to the proposed artificial liner thickness requirements because it was not provided with information to verify that a six to ten mil liner is appropriate in all circumstances. Commenters also asserted that a thickness of two feet for constructed-earthen liners is unnecessary and that in- situ substratum in some areas can meet the hydraulic conductivity requirement. After review and discussion, the Commission included in the proposed Subchapter B requirements language that would allow construction of a pit in in-situ substratum that meets hydraulic conductivity of 1 x 10 ^-7 cm/sec in lieu of artificial or constructed-earthen liner.

Another issue concerned the proposed operation requirements for authorized pits, specifically the requirement that a person maintain a freeboard of at least two feet in a pit. Current §3.8 does not contain specific requirements for freeboard or berms. Commenters asserted that a freeboard of two feet is not enough in certain areas and too much in others and that any freeboard requirement should be tied to rainfall. The Commission finds that rainfall is not the only reason for maintaining certain freeboard. A specific standard assures a freeboard that is generally adequate in all circumstances. The Commission made no change to the freeboard requirement in the proposed new rules.

One other issue raised by commenters concerned the requirements for closure of authorized pits. The proposed language would require that reserve pits with a chloride concentration of greater than 6100 mg/l be dewatered in 30 days and backfilled and compacted in 120 days, and that other reserve pits be dewatered, backfilled, and compacted in 120 days. Current §3.8 allows one year for operators to dewater, backfill, and compact a reserve pit that contains low chloride water base drilling fluid with a chloride concentration of 6100 mg/l or less, and allows 30 days to dewater and a year to backfill and compact other reserve pits. Commenters assert that 120 days is not an adequate amount of time to allow reserve pit to dry out for proper closure. The Commission changed the proposed language to allow 180 days to dewater, backfill, and compact all authorized pits, and to require a liner for reserve pits with a chloride content of greater than 3000 mg/l. The Commission proposes to retain the requirement to dewater within 30 days a reserve pit with a chloride content of greater than 3000 mg/l.

Another issue concerned liner integrity during pit closure. The version of proposed Subchapter B that was discussed at the workshops would have required that a person maintain liner integrity during closure of a pit that is required to be lined. Current §3.8 contains no specific liner requirements. Commenters asserted that integrity of the liner cannot be maintained during closure. They asserted that artificial liners are torn up during closure and pieces of plastic "float" to the ground surface, whether or not a cap is installed over the closed pit. After discussion, the Commission revised the proposed language to allow either an artificial or constructed-earthen liner in those instances where the rule requires a liner, and to delete the requirement to maintain liner integrity during closure.

Another issue concerned authorizing burial of oil and gas waste. Subchapter B would continue the practice of authorizing burial of dewatered pit solids in a reserve pit. Commenters asserted that the Commission should take the opportunity now to prohibit leaving any oil and gas waste in place. These commenters asserted that anything buried will eventually pollute groundwater; and that all waste should be taken to off-site disposal facility. The Commission finds that the proposed lining and closure standards will be adequate to prevent pollution of subsurface water from burial of reserve pit solids and has made no change to the proposed language.

One final major issue concerned protection of surface and subsurface water. Both the language currently in §3.8 and the language in proposed Subchapter B would require protection of all surface and subsurface water. Some commenters asserted that liners should not be required in areas where ground water is not "usable." The Commission determined that the statutory authority for the rule and subchapter requires protection of "surface and subsurface water" and does not distinguish between classes of water. The Commission believes that it must use the most protective term in a general rule for statewide application and, therefore, made no change to the proposed language in response to this comment.

G. Data and Methodology Used In Performing the Analysis.

The Commission relied primarily on its experience in the Districts and Austin in applying and enforcing the provisions of current §3.8; on information in comments received in 1997, 1998, and 2002; and on information from the Oilfield Cleanup Program in performing this analysis. Cost figures came from generally available public sources as indicated on the tables attached to this analysis. Presumptions were based primarily on input from District Directors in the field.

Background or baseline cost data for exploration and operations are provided in API (1998) and EIA (2000). API (1998) provides detailed state-by-state data on drilling expenditures in the United States. In Texas the average well was drilled to a depth of 5000 to 7500 feet and cost $610,000. EIA (2000) reports estimated costs and cost indices for domestic oil and natural gas field equipment and production operations for representative leases by region, depth, and production rate. Price changes for oil and gas, changes in taxes on oil and gas revenues, and environmental factors, such as compliance costs and lease availability, have a significant impact on the number and cost of oil and gas wells drilled.

References Cited:

The Commission relied on information in the following sources:

American Petroleum Institute, January 1989, "API Environmental Guidance Document Onshore Solid Waste Management in Exploration and Production Operations," API, Washington, D.C.

American Petroleum Institute, November 1, 1989, "Bulletin on the Generic Hazardous Chemical Category List and Inventory for the Oil and Gas Exploration and Production Industry," Bulletin E1, First edition, API, Washington, D.C.

American Petroleum Institute, November 1991, "Waste Minimization in the Petroleum Industry: A Compendium of Practices," API, Washington, D.C.

American Petroleum Institute, 1998, 1997 Joint Association Survey on Drilling Costs: American Petroleum Institute, Washington, D.C., 111 pages.

Energy Information Agency, 2000, Costs and Indices for Domestic Oil and Gas Field Equipment and Production Operations-- 1996 through 1999: U.S. Department of Energy Information Agency DOE/EIA-0185(2000), 107 pages.

Deuel, L., September 1990, "Evaluation of Limiting Constituents Suggested for Land Disposal of Exploration and Production Wastes," In: Proceedings of the First International Symposium on Oil and Gas Exploration and Production Waste Management Practices , sponsored by the U.S. Environmental Protection Agency, September 10-13, 1990, New Orleans, LA. pp. 411-430.

Interstate Oil Compact Commission, December 1990, "EPA/IOCC Study of State Regulation of Oil and Gas Exploration and Production Waste," IOCC, Oklahoma City, OK.

Interstate Oil and Gas Compact Commission, April 1993, "Texas State Review: IOGCC/EPA State Review of Oil and Gas Exploration and Production Waste Management Regulatory Programs," IOGCC, Oklahoma City, OK.

McFarland, M., Veckert, D., and Hartman, S., September 1990, "Evaluation of Selective-Placement Burial for Disposal of Drilling Fluids in West Texas," In: Proceedings of the First International Symposium on Oil and Gas Exploration and Production Waste Management Practices , sponsored by the U.S. Environmental Protection Agency, September 10-13, 1990, New Orleans, LA.

Railroad Commission of Texas, Water Protection Manual, 1987, March 1988, June 1988, 1990, 1991, 1992, May 1993, August 1993, 1999, and 2000, Railroad Commission of Texas.

Railroad Commission of Texas, Waste Minimization Manual, 1994, 1999, and 2001, Railroad Commission of Texas.

Society of Petroleum Engineers, March 1993, Proceedings of Society of Petroleum Engineers/EPA Exploration and Production Environmental Conference, San Antonio, TX.

Spell, R., Hall, C., and Pontiff, D., et al. , September 1990, "Evaluation of the Use of a Pit Management System," In: Proceedings of the First International Symposium on Oil and Gas Exploration and Production Waste Management Practices , sponsored by U.S. Environmental Protection Agency, September 10-13, 1990, New Orleans, LA.

Thurber, N., September 1990, "Waste Minimization in E&P Operations," In: Proceedings of the First International Symposium on Oil and Gas Exploration and Production Waste Management Practices , sponsored by U.S. Environmental Protection Agency, September 10-13, 1990, New Orleans, LA.

U.S. Environmental Protection Agency, January 2000, Associated Waste Reports.

U.S. Environmental Protection Agency, 1987, Report to Congress: "Management of Wastes from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy," EPA Office of Solid Waste and Emergency Response, Washington, D.C., December 31, 1987.

U.S. Environmental Protection Agency, 1988, "Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes," 53 FR 25446-25459, July 6, 1988.

U.S. Environmental Protection Agency, 1993, "Clarification," 58 FR 15284-15287, March 22, 1993.

H. Explanation of Whether the Provisions of Proposed Subchapter B Specify a Single Method of Compliance.

All of the new rules (except for those concerning the Coastal Management Program (CMP)) proposed in new Subchapter B are potentially subject to proposed new §4.166, which states, "A person may request an alternative to the provisions of this subchapter, except for those sections listed in subsection (b) of this section, by submitting to the Commission a written request and demonstrating good cause. The Commission shall review each written request on a case-by-case basis and may approve the alternative if the Commission determines that the requested alternative protects the public health, safety and the environment." Thus, except for CMP provisions in Division 9 of Subchapter B, the provisions of Subchapter B do not specify a single method of compliance.

The Commission is required to use the methods of compliance in Division 9, relating to the CMP, in order to maintain Texas' favorable status under the federal Coastal Zone Management Act.

I. Explanation of Why Provisions That Do Specify a Single Method of Compliance are Preferable to Adopting a Flexible Regulatory Approach, Such As a Performance Oriented, Market Based, or Market Based Approach.

This part of the Draft Impact Analysis is not applicable.

J. Statement of Opportunity for Public Comment on Draft Impact Analysis.

Public comment on this Draft Impact Analysis may be submitted to the Commission in accordance with public comment provisions in the preamble for proposed new Subchapter B, and all comments will be addressed in the publication of the final regulatory analysis.

Steven Seni, Assistant Director, Environmental Services, Oil and Gas Division, has determined that for each year of the first five year that the proposed new rules will be in effect, there will be no fiscal implications for state or local governments as a result of enforcing or administering the proposed new rules.

David Cooney, Assistant Director, Environmental Section, Office of General Counsel, has determined that for each year of the first five years the proposed new rules in Subchapter B will be in effect, there will be costs of compliance for affected operators who may be small businesses, micro-businesses, or individuals. However, these proposed new rules are generally consistent with current Commission practices, and the Commission finds that they are necessary to meet the existing "no pollution" standard of proposed new §4.101. Primary sources of new costs for operators include new siting restrictions, which may prohibit pits and disposal methods at certain locations, thereby requiring the use of above-ground tanks and, possibly, off-site disposal of certain wastes. In addition, new numerical criteria for the waste/soil mixture after authorized landfarming, and authorized disposal of wastes by burial may result in the need for additional soil analysis. Because this analysis often may be accomplished in the field, Mr. Cooney anticipates that such costs will be negligible. Also, compliance with the new requirements to use liners in certain authorized and permitted pits will result in increased costs.

Mr. Cooney has calculated the following estimates concerning potential change in cost for specific activities in the amendments. For activities covered by proposed new §4.115, analytical costs associated with the authorized landfarming of low chloride water-based drilling fluids from a reserve pit are estimated to be approximately $65 per sample. Lining costs associated with reserve pits, mud circulation pits, and completion/workover pits that would require a liner are estimated to be from $100 to $2000 per pit. For waste permitted by another agency and for sewage, a permit will no longer be required, resulting in a potential decrease in costs. Analytical costs associated with the discharge of stormwater to the surface are estimated to be approximately $37 per sample, the same as required under existing §3.8 for a permit for such a discharge; however, because the proposed rule eliminates the current requirement that a person apply for and obtain a permit from the Commission for such discharge, Mr. Cooney anticipates a net savings.

Activities regulated by proposed new §4.118 may also result in new costs. For example, fresh water based reserve/mud pits not sited on Quaternary sand and more than 20 feet above groundwater may incur estimated analytical costs of $81 per sample before closure. Reserve/mud pits that are salt-water based, or oil based, or sited on Quaternary sand, or are less than 20 ft above ground water may incur liner costs estimated to be from $500 to $2000 per pit and capping costs estimated to be from $100 to $1000 per pit. Completion/workover pits may result in estimated liner costs of $75 to $500 per pit. Basic sediment pits may incur estimated liner costs from $75 to $300 per pit. For any flare pit that is not located at a tank battery or at a facility intermediate to tank battery, or that does not have a continuous flare, there may be estimated liner costs from $75 to $500 per pit, based on an estimated cost of $75 to $500 to line a basic sediment pit when a basic sediment pit is limited to a 50 barrel capacity. Water condensate pits may result in estimated liner costs from $75 to $500 per pit. Commission practice under §3.8 has been to allow small sumps, therefore Mr. Cooney anticipates no difference in cost.

Activities covered by proposed new §4.121 are not anticipated to result in increased costs due to siting restrictions because the proposed construction, operation and closure provisions in the proposed rule are consistent with current Commission practice under §3.8.

Mr. Cooney anticipates that any increase in cost as a result of the proposed new rules will be offset, at least in part, by the resulting reduction in the number of minor permits required for discharge of storm water, discharge of hydrostatic test water, and management of oil and gas wastes at facilities permitted by entities other than the Commission, which will reduce paperwork and the associated costs for both industry and the Commission. In addition, more specific permit application requirements should result in more complete and acceptable permit applications, which will reduce correspondence, time, and effort involved in completing an application and getting it through the permitting process.

Mr. Cooney has also determined that the public benefit from adoption of the proposed new rules will be more specific standards for prevention of pollution from waste associated with oil and gas exploration, production, and development. These standards will aid operators in eliminating or reducing potential sources of pollution and are consistent with industry practices. Finally, the Commission finds that the costs of compliance are more than offset by the public benefit of enhanced protection of surface and subsurface water arising from implementation of the proposed new rules.

Comments on the proposed amendments may be submitted to Steve Seni, Assistant Director of Environmental Services, Oil and Gas Division, Railroad Commission of Texas, P. O. Box 12967, Austin, Texas, 78711-2967, or by electronic mail to Steven.Seni@rrc.state.tx.us. Comments must be submitted by 5:00 p.m. on the sixtieth day after publication in the Texas Register . For more information, call Dr. Seni at 512-463- 3269. The Commission specifically requests comment and documentation concerning the cost of analytical and lining requirements in the proposed rule.

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