[46 Pa.B. 6431]
[Saturday, October 8, 2016]

[Continued from previous Web Page]

§ 78a.55. Control and disposal planning; emergency response for unconventional wells

 Section 78a.55 of this final-form rulemaking requires all well operators to develop and implement a site-specific PPC plan for oil and gas operations. This change is needed clarify requirements in §§ 91.34 and 102.5(l). Additionally, site-specific PPC plans are needed to address the conditions present at each individual site, including local emergency contact information.

 There may be instances when the operator finds that a PPC plan prepared for one well site is applicable to another site. For example, conventional well sites that are all located in a single municipality with similar equipment present on each site might be able to ''share'' a single PPC plan that still nonetheless addresses the concerns facing each site. Each individual plan shall be analyzed prior to making a determination. It is not the intent of this final-form rulemaking to require each PPC plan be separately developed and different for each well site. The Department understands that many of the practices covered in the PPC plan are the same for a given operator. It is also not the intent of this final-form rulemaking to require that all PPC plans are revised annually. In many cases, if conditions at the site do not change, there will be no need to make revisions to the PPC plan.

 Commentators expressed concerns about § 78a.55(a) which simply reiterates the requirements already existing in §§ 91.34 and 102.5(l). Since § 78a.55(a) does not establish any new requirements, this subsection does not present any new burden on operators, yet referencing these requirements in Chapter 78a has value in reminding operators of those obligations. Operators may develop a single integrated PPC plan to satisfy the requirements of § 78.55(b). PPC plans satisfying the requirements of § 91.34 alone may not also satisfy the requirements of § 102.5(l). PPC plans are required for production and storage of pollutants as well as for pipelines and processing. This final-form rulemaking does not exempt the requirements of either § 91.34 or § 102.5(l) for unconventional activities. The purpose of § 78a.55 as it relates to PPC planning is largely to cross-reference existing requirements in other regulatory chapters implemented by the Department.

 For these reasons, the Department has retained the requirement to develop and implement site-specific PPC plans in this final-form rulemaking.

 It appears that commentators incorrectly assumed that every single site where an impoundment, production, processing, transportation, storage, use, application or disposal of pollutants occur must have the PPC plan posted onsite at all times. This final-form rulemaking does not require persons to post PPC plans at these sites at all times. This final-form rulemaking does not require a PPC plan for the impoundment, production, processing, transportation, storage, use, application or disposal of pollutants to be maintained on the site at all.

 Instead, § 78a.55(e) requires well operators to maintain a copy of the PPC plan at the well site during drilling and completion activities only. This requirement is needed because the site is active during drilling and completion activities and there is an increased risk of a spill, release or other incident. In the event of an incident, the purpose of the onsite PPC plan is to allow the operator to quickly minimize any impact. The Department recommends well operators to maintain the PPC plan on the site whenever active operations are occurring on the well site, including during alteration and plugging activities.

 Section 78a.55(e) also requires well operators to provide the PPC plan to the Department, the Fish and Boat Commission or the landowner upon request. The requirement to provide the PPC plan to the Fish and Boat Commission upon request is needed because the Fish and Boat Commission has jurisdictional responsibilities over waters of the Commonwealth. The PPC plan enables the Fish and Board Commission investigate areas of concern that fall under its jurisdiction. The Department has determined that this is reasonable and appropriate to ensure compliance with all applicable laws. Additionally, the requirement to provide landowner a copy of the PPC plan upon request in needed because landowners have a vested interested in the contents of the PPC plan and should have access to the plan. Therefore, it is in the best interest of the landowner to be provided a copy of the PPC plan so they understand the activities and potential pollutants and how they will be controlled in the event of a spill or release.

§ 78a.56. Temporary storage

 Section 78a.56 regulates temporary storage of regulated substances used or produced at the well site during drilling, altering, completing, recompleting, servicing and plugging the well. The purpose of this section is to ensure that temporary storage at the well site during these activities protects public health, safety and the environment. This section is needed to minimize spills and releases into the environment.

 Many commentators expressed concern with the use of pits at unconventional well sites. Section 78a.56 of this final-form rulemaking bans the use of pits for temporary waste storage at unconventional well sites. The Department has determined that it is appropriate to remove this practice because it is not commonly used by unconventional operators. Additionally, the typical type and scope of use by unconventional operators is generally incompatible with technical standards for temporary pits prescribed under § 78.56.

 Many unconventional operators have moved to utilizing modular aboveground storage structures to store water and wastewater on well sites. These structures come in many shapes, sizes and designs. The permit-by-rule structure contemplated by § 78a.56 for temporary storage on the well site does not provide adequate protection to public health and safety or the environment due to the variability of the designs of these structures. Section 78a.56 seeks to codify current requirements of Department review and approval of modular aboveground storage structures prior to their use to store regulated substances on a well site. In addition, § 78a.56 will result in more efficient implementation of current requirements by including a requirement for the Department to publish approved structures on its web site. This requirement will eliminate the need for the Department to conduct multiple evaluations of the same design and allows for a single Statewide approval. It is important to note that the Statewide approval will be applicable to the design of the structure only. Section 78a.56(a)(3) requires the operator to obtain siting approval from the Department for site-specific installation of all modular aboveground storage structures for each individual well site where use of the modular aboveground storage structure is proposed. The Department evaluates proposed modular aboveground storage structures on a case by case basis to determine whether the proposed structure will provide equivalent or superior protection. The Department reviews not only modular designs but also site-specific construction and topographic conditions. The Department's web site will list approved modular structures but authorization of the process will still be required to ensure proper siting of the facility. This provision was originally proposed to include all modular aboveground storage structures, but in response to comments the Department amended the requirement to apply to only those structures which exceed 20,000 gallons of total capacity.

 In the proposed rulemaking, § 78.56(a)(5)—(7) addressed security requirements for pits, tanks and approved storage structures and required operators to equip all tank valves and access lids to regulated substances with reasonable measures to prevent unauthorized access by third parties such as locks, open end plugs, removable handles, retractable ladders or other measures that prevent access by third parties. In addition, for unconventional well sites, a fence was required to completely surround all pits to prevent unauthorized acts of third parties and damage caused by wildlife unless an individual was continuously present at the well site. Finally, operators of unconventional well sites were required to display a sign on or near the tank or other approved storage structure identifying the contents and an appropriate warning of the contents such as flammable, corrosive or a similar warning.

 The Department received significant public comment from unconventional operators that the requirements to install fences around all pits or provide continuous presence on unconventional well sites was inappropriate and would not be effective. As previously noted, the Department revised § 78a.56 to disallow the use of pits on unconventional well sites and accordingly deleted the requirement to install fencing around pits on unconventional well sites. The Department also retained the requirement to maintain signs on tanks or other approved storage structures to prevent confusion when multiple storage structures are located in close proximity on a well site, and to assist emergency response personnel in properly identifying risks at well sites.

§ 78a.57. Control, storage and disposal of production fluids

 Section 78a.57 in this final-form rulemaking contains requirements that apply to permanent storage of production fluids. The purpose of this section is to ensure that storage during the production of well, when there is less activity occurring at the well site, provides protection of public health, safety and the environment. This section is needed to minimize spills and releases to the environment.

 In the proposed rulemaking, § 78.57(e) banned further use of underground storage tanks and would have required unconventional operators to remove all underground storage tanks within 3 years of the effective date of the final regulations. The Department received significant public comment on this provision from unconventional operators arguing that it was inappropriate, overly burdensome and exorbitantly expensive. As a result of public comment, the Department amended § 78a.57(e) in this final-form rulemaking to allow the use of buried tanks by unconventional well site operators and does not require removal of existing buried tanks. Underground storage tanks warrant extra scrutiny because they are not as easily inspected and can provide a more direct conduit for contamination into groundwater and therefore provisions in this final-form rulemaking require the location of all existing and any new underground storage tanks at well sites to be reported to the Department.

Corrosion control

 Section 78a.57(f) implements section 3218.4(b) of the 2012 Oil and Gas Act, which requires that permanent aboveground and underground tanks comply with the applicable corrosion control requirements in the Department's storage tank regulations. Some commentators argued that these provisions should not apply because storage tanks on well sites are not permanent. In the context of tanks regulated under § 78a.56, the Department agrees because those tanks are used only during drilling and completion of the well and are subject to the well site restoration time frames. However, in the context of tanks regulated under § 78a.57 for the storage of production fluids, the Department disagrees. These tanks are in place on the well site for the duration of the productive life of the well which can be decades or in some cases centuries. If tanks that are in service for this duration are not considered permanent, then no tank would ever be considered permanent under this interpretation. Accordingly, the tanks regulated by § 78a.57 are permanent and subject to the corrosion control requirements in section 3218.4(b) of the 2012 Oil and Gas Act.

 Commentators also argued that because the Storage Tank and Spill Prevention Act (35 P.S. §§ 6021.101—6021.2104) specifically exempts underground and aboveground storage tanks located at oil and gas well sites from regulation, there are no applicable corrosion control requirements in the Department's storage tank regulations. Therefore, regulations specifying that operators shall comply with corrosion control requirements in §§ 245.432 and 245.531—245.534 are inappropriate and not authorized by section 3218.4(b) of the 2012 Oil and Gas Act. The Department disagrees with this interpretation. Section 3218.4(b) of the 2012 Oil and Gas Act expressly requires permanent aboveground tanks to comply with the applicable corrosion control requirements in the Department's storage tank regulations. Additionally, section 3218.4(b) of the 2012 Oil and Gas Act was enacted after the Storage Tank and Spill Prevention Act.

 The Department notes that this final-form rulemaking does not require retroactive application of the corrosion control requirements. Only new, refurbished or replaced aboveground and underground storage tanks must comply with the applicable corrosion control requirements. In addition, the Department also explicitly deleted the requirement to use Department certified inspectors to conduct inspections of interior linings or coatings as not ''applicable,'' which will alleviate some burden on oil and gas operators. Finally, the Department notes that operators may choose to use nonmetallic tanks which can often be less expensive than a steel equivalent and do not require any additional cost to ensure protection from corrosion.

Secondary containment

 Section 78a.57(c) of this final-form rulemaking requires secondary containment for aboveground tanks that contain brine and other fluids produced during operation of the well. Since well sites in the production phase are not typically inspected by the Department with the same frequency as those in the well development, restoration and plugging phases, and do not have continuous operator presence, the Department feels it is necessary to require secondary containment for aboveground tanks used to store brine and other fluids produced during operation of the well to prevent undetected releases into the environment.

 Releases of brine from aboveground tanks used for production fluids are uncontrolled and usually undetected as they occur. Secondary containment around aboveground tanks will prevent these releases from entering the environment until they are detected.

 To reduce the burden on operators, this final-form rulemaking does not require retroactive application of the secondary containment requirements. The Department does not require secondary containment to be installed until a tank or one tank in a series of tanks is added, refurbished or replaced. Finally, commentators raised the concern of a larger footprint created by secondary containment where available area may be an issue. This concern is addressed by allowing the use of double-walled tanks capable of detecting a leak in the primary containment to fulfill the requirements in this subsection.

§ 78a.58. Onsite processing

 Section 78a.58 codifies existing practices to allow onsite waste processing to occur provided all of the waste processed on the site is either generated at the site or will be beneficially reused at the site after approval is obtained from the Department. The purpose of this provision is to encourage recycling and reuse in hydraulic fracturing operations. These provisions are needed to ensure that processing activities are conducted in a way that protects public health, safety and the environment. Additionally, the purpose of these provisions is to minimize spills and releases to the environment.

 This final-form rulemaking also seeks to streamline this process by including a requirement for the Department to publish approved processes on its web site. This requirement will eliminate the need for the Department to conduct multiple evaluations of the same process and allows for a single Statewide approval. Once a process receives approval, operators wishing to utilize that process would be required only to register use and provide notification to the Department 3 days prior to initiating processing. These sections also include exemptions from the requirement to obtain approval and register with the Department prior to conducting the following processes: blending wastewater with fresh water, aeration and filtering solids from fluids. The Department does not believe that specific Department oversight is necessary for these processes.

 The Department received significant public comment on this section indicating that allowing operators to conduct waste processing on well sites is inappropriate and not protective of public health and safety or the environment. The Department disagrees and believes that it is appropriate to allow waste processing on a well site to facilitate beneficial reuse of waste and efficient operations, so long as appropriate protections are in place as required by these amendments.

 The Department received comments that requiring an operator to wait for solid waste remaining after the processing or handling of fluids under § 78a.58 be characterized under § 287.54 (relating to chemical analysis of waste) before the solid waste leaves the well site requires too much time (27 days) to store it onsite until the sample analysis is received. The Department requires that a waste characterization be conducted in accordance with § 287.54. The Department believes that this is an appropriate cross-reference, as § 78a.58(h) only concerns those wastes that will be leaving the well site where they were generated. Once the waste leaves the well site, the exemptions under section 3273.1 of the 2012 Oil and Gas Act no longer apply and the waste management program regulations govern testing and handling of the waste.

 Commentators also noted that waste processing often generates high concentrations of TENORM. The Department's 2015 TENORM Study Report presented several observations and recommendations regarding radioactive material associated with the oil and gas industry. Although the study outlines recommendations for further study, it concluded there is little potential for harm to workers or the public from radiation exposure due to oil and gas development. While the study concluded that there is little potential harm to workers or the public from radiation exposure due to oil and gas development, the study observed that there is potential for worker and public exposure from the processing and potential spilling of wastewater from oil and gas operations. There is also the potential to produce loads of TENORM waste with radium-226/-228 concentrations greater than 270 pCi/g, which is the threshold for United States Department of Transportation regulations regarding the labelling, shipping and transport of Class 7 hazmat radioactive material.

 The Department remains committed to protecting the public from unnecessary exposure to radiation and is actively pursuing the recommendations of the 2015 TENORM Study Report. The Department added § 78a.58(d) to this final-form rulemaking. This new subsection requires an operator processing fluids onsite to develop a radiation protection action plan which specifies procedures for monitoring and responding to radioactive material produced by the treatment process (for example, sludges or filter cake). This section also requires procedures for training, notification, recordkeeping and reporting to be implemented. This will ensure that workers, members of the public and the environment are adequately protected from radioactive material that may be found in fluids processed on the well site.

 Other commentators indicated that this section is overly burdensome and does not go far enough to support processing, recycling and beneficial reuse of fluids and other waste materials at well sites. It is the intent of this section to support waste processing on a well site to facilitate beneficial reuse of waste and efficient operations; however, certain activities present enough of an environmental hazard that the Department should have the opportunity to review and approve those activities prior to implementation.

§ 78a.59a. Impoundment embankments

§ 78a.59b. Well development impoundments

 In this final-form rulemaking, §§ 78a.59a and 78.59b (relating to impoundment embankments; and well development impoundments) establish construction standards for well development impoundments. Currently, oil and gas operators use impoundments to store freshwater and other fluids approved by the Department for use in drilling and hydraulic fracturing activities that do not trigger the permitting requirements in § 105.3(a)(2) and (3) and are unregulated by the Department. The provisions in these sections seek to outline the necessary requirements to ensure that those facilities that do not meet the Chapter 105 permitting requirements have structural integrity and do not pose a threat to waters of the Commonwealth. This is necessary because the scope and type of use of well development impoundments by the oil and gas industry are significantly different than the scope and type of use by other industries. The Department has observed the use of these impoundments to hold up to 16 million gallons of freshwater and other approved fluids varying in quality that are usually not indigenous to the local watershed where these facilities are constructed. For this reason, the escape of that water may pose a threat of pollution to waters of the Commonwealth.

 The Department's structural standards and measures in §§ 78a.59a and 78.59b are intended to prevent leaking of well development impoundments in the groundwater and surrounding surface waters. Failure to construct well development impoundments in a structurally sound manor would allow for the potential for a catastrophic failure of the impoundment that may cause serious harm to public health and to the environment.

 Section 78a.59b(d) and (f) specifies that an impervious liner must be used and the bottom of the well development impoundments must be placed be at least 20 inches above the seasonal high groundwater table to prevent groundwater infiltration. The Department received comments stating that well development impoundments should be required to follow Chapter 105. The Department disagrees because these regulations only pertain to dams that are not regulated under Chapter 105 because they do not meet the height and volume thresholds. The Department also received comments saying that the regulations for well development impoundments unfairly target the oil and gas industry. The Department disagrees and believes that adherence to § 78a.59a provides for the structural integrity of the impoundment to provide adequate public safety and that § 78a.59b provides reasonable assurances that the water placed in the impoundments does not pose an environmental hazard. Failure to construct well development impoundments in a structurally sound manner would allow for the potential for a catastrophic failure of the impoundment that may cause serious harm to public health and to the environment.

 This final-form rulemaking also establishes registration of existing and future well development impoundments with the Department electronically through its web site. This is needed to allow the Department to inspect the well development impoundments, especially those that do not require an erosion and sediment control permit under Chapter 102.

 Also, this final-form rulemaking establishes that well development impoundments need to be restored within 9 months of completion of hydraulic fracturing of the last well serviced by the impoundment. An extension for restoration may be approved under § 78a.65(c). While extensions for well development impoundments are not directly addressed in Act 13, the Department believes it is reasonable to tie the restoration requirements associated with well sites to well development impoundments because well development impoundments are contingent on the existence of well sites being developed and should not exist in perpetuity on their own. The Department believes that the sites used for well development impoundments need to be returned to preconstruction contours and support the prior land uses that existed to the extent practicable. Land owners may request to the Department in writing that the impoundment embankments not be restored provided that the synthetic liner is removed.

Technical adjustments

 Several changes to this section in this final-form rulemaking include technical adjustments of the requirements. In § 78a.59a(a)(5), soil classification sampling rates are adjusted from one sample per 1,000 cubic yards to one sample per 10,000 cubic yards which is a more appropriate sampling rate. A requirement is also added to § 78a.59a(a)(5) to describe and identify soils used for embankment construction in accordance with ASTM D-2488—09A (Standard Practice for Description and Identification of Soils (Visual-Manual Procedure)).

 Soil compaction standards are included in § 78a.59a(a)(8)(iv) of this final-form rulemaking, with reference to several ASTM test methods. The Department also added language in § 78a.59a(b) allowing an operator to request a variance from the specific technical requirements in these sections upon demonstration that the alternate practice provides equivalent or superior protection to the requirements of the section.

Mine influenced water

 In § 78a.59b(h), this final-form rulemaking allows operators to request to store MIW in well development impoundments. This provision seeks to codify the existing practices outlined in the Department's white paper ''Establishment of a Process for Evaluating the Proposed Use of Mine Influenced Water (MIW) for Natural Gas Extraction.'' Further, the purpose of these provisions is to promote the voluntary use of MIW by the oil and gas industry.

 Some commentators were concerned about the potential to allow operators to store MIW in well development impoundments. These commentators asserted that the quality of MIW varies greatly throughout this Commonwealth and the term includes MIW that has been treated, which may be very high quality. The Department disagreed with these commentators because § 78a.59b(h) specifies that before MIW is allowed to be stored in a well development impoundment, the Department will review and approve the storage based on a variety of factors including the quality of the MIW and the risks of storage of the water. MIW that does not meet the Department's water quality standards to be stored in a well development impoundment may not be stored in a well development impoundment absent additional protections and evaluation. The Department believes that allowing the use of MIW for well development has a positive impact on the environment by finding a beneficial use for MIW that also reduces the consumption of freshwater from the Commonwealth's waterways. In some cases, use of MIW by the oil and gas industry can provide funding for treatment systems to continue operating. Encouraging the use of alternative water sources, including recycled water, MIW and treated wastewater, has been supported by the STRONGER organization to provide additional sources of water for operators to use for well development purposes.

Security issues (fences)

 Section 78a.59b(e) of this final-form rulemaking requires that a fence must completely surround a well development impoundment to prevent unauthorized acts of third parties and damage caused by wildlife unless an individual is continuously present at the impoundment. There were comments from operators who were concerned that no matter what type of fence they erect around an impoundment, it could never absolutely prevent entry. This provision is needed due to the size and depth of many well development impoundments plus the slickness of the installed liner. Additionally, this provision is needed to prevent unintended entry by landowners or other members of the public. Fences are also needed to deter wildlife from damaging the structural integrity of these facilities. Well development impoundment liners can easily be damaged by large animals and even smaller ones with claws trying to escape after falling in.

§ 78a.59c. Centralized impoundments

 This final-form rulemaking requires all centralized impoundments to comply with permitting requirements in Subpart D, Article IX, or close by October 8, 2019. When initially proposed, this section included provisions to codify the Department's existing centralized impoundment permit program by providing technical specifications for construction and operation of centralized waste storage impoundments. The Department received significant public comment on this provision.

 Commentators argued that the standards set for centralized impoundments for oil and gas operations were less stringent than other Department regulations that address closure of impoundments (for example, Chapter 289 (relating to residual waste disposal impoundments)). The Department believes that centralized impoundments should be regulated in the same manner as other waste transfer facilities in this Commonwealth. Therefore, the Department determined that all future centralized wastewater impoundments will be regulated by the Department's Waste Management Program. This section will require oil and gas operators to comply with the residual waste management regulations which contain requirements for managing residual waste properly, and these requirements apply to residual waste that is generated by any type of industrial, mining or agricultural operation. This change will ensure that the Department does not impose disparate requirements or disproportionate costs on one particular economic or extractive sector.

§ 78a.60. Discharge requirements

 This final-form rulemaking continues to allow operators to discharge tophole water or water in a pit as a result of precipitation onto a vegetated area capable of absorbing the water and filtering solids. Commentators argued the Department should ban the discharge of tophole water for a number of reasons. This final-form rulemaking allows the discharge of tophole water or water in a pit from precipitation only if it includes no additives, drilling muds, regulated substances or drilling fluids other than gases or fresh water. In addition, the water must meet certain water quality standards and be discharged to an undisturbed, vegetated area capable of absorbing tophole water and filtering solids in the discharge. Tophole water or water in a pit as a result of precipitation may not be discharged to waters of the Commonwealth except in accordance with Chapters 91—93 and 95. Land application of water in accordance with this section is not expected to cause any significant environmental impact. This provision has been in effect since Chapter 78 was initially promulgated in 1989 and the Department continues to believe that it is an environmentally sound method of dealing with this material.

§ 78a.61. Disposal of drill cuttings

 Comments were received urging the Department to ban the use of all pits and to ban onsite waste disposal. The Department amended this final-form rulemaking to ban the use of pits for temporary waste storage at unconventional well sites. The Department determined that it is appropriate to prohibit this practice because it is not commonly used by unconventional operators due to the volume and nature of wastes generated at unconventional well sites. Additionally, the typical type and scope of use by unconventional operators is generally incompatible with technical standards for temporary pits prescribed under § 78.56. As a result, unconventional operators will no longer be permitted to dispose of residual waste including contaminated drill cuttings in a pit at the well, unless the pit is authorized by a permit obtained from the Department.

 The Department clarified that the cutoff for addressing drill cuttings under subsections (a) and (b) versus under subsection (c) is the cuttings above and below the surface casing seat. The former have less restrictive yet still protective disposal requirements. A requirement to give the surface landowner notice of the location of disposal was added to subsection (e). Some commentators believed that rather than require notice, the Department should require landowner consent before allowing for disposal of drill cuttings. The Department disagrees that the regulations should include a requirement for landowner permission or consent. Prior to entering into a lease agreement with the well operator, the landowner may discuss and agree upon the terms and conditions that relate to the type of operations that will occur on the property. Additionally, the Department believes that the provisions of § 78a.61 (relating to disposal of drill cuttings) are sufficiently protective that an operator meeting those requirements should not be required to obtain prior consent. The Department does believe that transparency and notice are important concerns, however, and has added language to § 78a.61 requiring operators to provide notice to surface landowners of the location of cuttings disposal or land application.

§ 78a.62. Disposal of residual waste—pits

 The primary change to § 78a.62 was to take the prohibition on disposal of residual waste generated by unconventional operations in a pit that was proposed in § 78.62(a)(1) (relating to disposal of residual waste—pits) and replace it with a ban unless the operator can obtain an individual permit for the activity. Given that other generators of residual waste can obtain permits for proper disposal of residual waste, the Department did not feel that an outright ban would withstand scrutiny.

§ 78a.63. Disposal of residual waste—land application

 The primary change to § 78a.63 was to take the prohibition on disposal of residual waste generated by unconventional operations through land application that was proposed in § 78.63(a)(1) and replace it with a ban unless the operator can obtain an individual permit for the activity. Given that other generators of residual waste can obtain permits for proper disposal of residual waste, the Department did not feel that an outright ban would withstand scrutiny.

§ 78a.63a. Alternative waste management

 This is a catch-all section added in this final-form rulemaking indicating that an operator may seek Department approval to manage waste in a manner other than that outlined in §§ 78a.56—78a.63, provided the operator can demonstrate that the practice provides equivalent or superior protection to the requirements in these sections. The concept is embedded in several sections of this final-form rulemaking, but the Department believes that this catch-all provision will serve as a backstop to those provisions.

§ 78a.64. Secondary containment around oil and condensate tanks

 Section 78.64 (relating to containment around oil tanks) requires secondary containment that meets Federal requirements under 40 CFR Part 112 (relating to oil pollution prevention) to be implemented around oil tanks to prevent the discharge of oil into waters of the Commonwealth. The Department has expanded this requirement to include tanks that contain condensate (light liquid hydrocarbons) because the EPA considers condensate that is liquid at atmospheric pressures and temperatures to be ''oil.'' This final-form rulemaking change will apply to unconventional wells that produce condensate in § 78a.64.

 The Department received comments both for and against the Department's deletion of language requiring secondary containment for singular tanks with a capacity of at least 660 gallons in § 78a.64. The Department revised the language in § 78a.64 in this final-form rulemaking from 660 gallons to 1,320 gallons to be consistent with Federal Spill Prevention, Control and Countermeasure Plan regulations in 40 CFR Part 112. Making this change matches the Commonwealth's requirements to the National standards for regulation of oil and condensate storage.

 The Department received comments stating that ''containment'' was used in various contexts throughout the draft final-form regulations and was confusing. As a result, the Department added definitions for ''primary containment'' and ''secondary containment'' in § 78a.1. These terms are used in the throughout this final-form rulemaking when referring to specific types of containment.

 Section 78a.64 requires that all tanks that store hydrocarbons have secondary containment by October 9, 2016, or at the time the tank is replaced, refurbished or repaired, whichever is sooner.

§ 78a.64a. Secondary containment

 Section 3218.1 of the 2012 Oil and Gas Act (relating to notification to public drinking water systems) establishes the requirement for secondary containment systems and practices for unconventional well sites. As a result, the Department adds § 78a.64a in this final-form rulemaking to implement these statutory requirements for unconventional well sites.

 Secondary containment at unconventional well sites shall be used on the well site when any equipment used for any phase of drilling, casing, cementing, hydraulic fracturing or flowback operations is brought onto a well site and when regulated substances are brought onto or generated at the well site. This final-form rulemaking requires that all regulated substances, except fuel in equipment or vehicles, be managed within secondary containment. The Department received comments pointing out that section 3218.2(c) of the 2012 Oil and Gas Act (relating to containment for unconventional wells) lists six specific substances that must be stored in secondary containment and that this new section broadens the scope of that statutory list to include all regulated substances, including solid wastes and other regulated substances in equipment or vehicles. The commentators asked how this expansion is consistent with the intent of the General Assembly and the 2012 Oil and Gas Act and the need for this requirement. The Department acknowledges that section 3218.2(c) of the 2012 Oil and Gas Act does list six materials that require use of containment systems when stored on an unconventional well site but disagrees with the comment because section 402(a) of The Clean Streams Law (35 P.S. § 691.402(a)) states that whenever the Department finds that any activity creates a danger of pollution of the waters of the Commonwealth or that regulation of the activity is necessary to avoid pollution, the Department may, by rule or regulation, establish the conditions under which the activity shall be conducted. Additionally, the Department believes that it is the intent of the General Assembly to require regulated substances be stored in secondary containment by use of the language ''[u]nconventional well sites shall be designed and constructed to prevent spills to the ground surface or spills off the well site'' in section 3218.2(a) of the 2012 Oil and Gas Act. It has been well documented through studies and the Department's experience that the primary cause for pollution to the environment by oil and gas operations on well sites are unauthorized releases of regulated substances onto the ground. Secondary containment of all regulated substances is necessary to significantly reduce the potential for pollution on well sites.

 This final-form rulemaking establishes that chemical compatibility and maximum permeability standards must be met for materials used for secondary containment at unconventional well sites. The Department received comments stating that the ASTM D5747 standard in the proposed rulemaking for testing chemical compatibility is both time consuming and expensive. Also, that it is a standard for landfill liners and may not be practicable to allow for other materials to be used that meet the maximum permeability standard. The Department changed language in this final-form rulemaking to allow for chemical compatibility testing to be determined by a method approved by the Department. This will allow for the proper and most practicable testing methodology to be used based upon the material used for secondary containment at an unconventional well site.

 Secondary containment open to the atmosphere must be able to hold the volume of the largest aboveground primary container plus an additional 10% for precipitation. Removal of precipitation from secondary containment is required once the 10% of excess capacity is diminished. Stormwater that comes into contact with regulated substances stored within the secondary containment needs to be managed as residual waste. Double walled tanks capable of detecting leaks from primary containment are also allowed to be used. The Department received comments that section 3218.2(d) of the 2012 Oil and Gas Act does not require secondary containment systems. The Department interprets that section to mean that the container that additives, chemicals, oils or fuels are stored in is considered to be primary containment. Therefore, the containment capacity referred to that must be able to hold the contents of the largest container plus 10% for precipitation is secondary containment. Any other interpretation of section 3218.2(d) of the 2012 Oil and Gas Act would render the final phrase of the subsection (''. . .unless the container is equipped with individual secondary containment'') irrelevant. Therefore, it is clearly the intent of the General Assembly that secondary containment is required by the 2012 Oil and Gas Act. The Department received comments saying that stormwater that has not been discharged or discarded from secondary containment is not residual waste. The Department disagrees because stormwater in secondary containment that also contains regulated substances is considered to be residual waste, as defined in § 287.1 (relating to definitions), whether or not the stormwater has been discharged or discarded and shall be handled and disposed of accordingly.

 Secondary containment shall be inspected weekly to ensure integrity. Repairs to damaged or compromised secondary containment shall be done as soon as practicable. Secondary containment inspection and maintenance records shall be maintained and made available at the well site until the well site is restored. The Department received comments stating that for many operators it is not practical to store hard copies of inspection reports and maintenance records at the well site. As a result, the Department should allow for operators to provide these reports electronically to the Department upon request instead. The Department believes that because containment systems will be employed during drilling, casing, cementing, hydraulic fracturing and flowback operations, it is reasonable to make inspection reports and maintenance records available at the well site, because the site is normally manned during these operations. The Department is not requiring that the hard copies shall be stored onsite, but that operators shall be capable of these reports being made available upon request (physically or electronically) at the site at the time of the request. The Department needs these reports at the time of the inspection to determine that operators are doing their due diligence with secondary containment inspection and maintenance.

 Language pertaining to subsurface containment systems in the proposed rulemaking has been deleted after receiving comments that they should not be allowed. The Department concurred that subsurface containment systems are too impractical to be employed as a secondary containment system because they are difficult to inspect and they would require remedial steps to address the contaminated material within them whenever a spill would occur.

§ 78a.65. Site restoration

 Permanent changes to the surface of the land resulting from earth disturbance activities have the potential to cause pollution. In many watersheds throughout this Commonwealth, flooding problems from precipitation events, including smaller storms, have increased over time due to changes in land use and ineffective stormwater management. This additional flooding is a result of an increased volume of stormwater runoff being discharged throughout the watershed. This increase in stormwater volume is the direct result of more extensive impervious surface areas, combined with substantial tracts of natural landscape being converted to lawns on highly compacted soil or agricultural activities. The problems are not limited to flooding. Stormwater runoff carries significant quantities of pollutants washed from the impervious and altered land surfaces. The mix of potential pollutants ranges from sediment to varying quantities of nutrients, organic chemicals, petroleum hydrocarbons and other constituents that cause water quality degradation.

 Improperly managed stormwater causes increased flooding, water quality degradation, stream channel erosion, reduced groundwater recharge and loss of aquatic species. These and other impacts can be effectively avoided or minimized through better site design that minimizes the volume of stormwater generated and also requires treatment. PCSM requirements are already in § 102.8 and are needed to prevent pollution from improperly managed stormwater, and require utilization of stormwater management techniques that achieve stormwater runoff volume reduction, pollutant reduction, groundwater recharge and stormwater runoff rate control for all runoff events. The requirements of § 78a.65 are not more or less stringent than § 102.8, but are a reasonable approach to adapting the requirements of this section where needed for the industry detailed as follows.

 Section 78a.65 was essentially re-written after the first public comment period because as the Department considered all comments suggesting more stringent site restoration requirements as well as those against parts of the site restoration section, or the section in its entirety, it became exceptionally difficult to read through as the significantly edited language sacrificed readability with excessive strikethrough, underlining, all capitalized text, and the like. The Department decided there needed to be a clean write-up of the restoration requirements to be understood. However, substantively, the actual changes to the site restoration section do not deviate greatly from the proposed rulemaking.

 Several commentators were of the opinion that the proposed restoration requirements included in this final-form rulemaking were not stringent enough and should require more than restoration to approximate original conditions. These commentators wanted to see the restoration requirements require operators to re-establish prior existing biological communities and ecosystems as well as re-establish the entire site to its exact pre-existing conditions. This position proposed making § 78a.65 more stringent than § 102.8. The Department does not believe that it is necessary to include technical performance standards including requirements for type and density of perennial vegetation, soil characteristics and drainage patterns in this section because those issues are already appropriately addressed by the requirements. Projects meeting the requirements will not pose a threat of significant environmental harm. Projects that trigger the Chapter 102 requirements for an erosion and sediment control permit shall submit a Site Restoration/Post-Construction Stormwater Management Plan to the Department for review and approval prior to construction of the site. Additionally, this section requires operators to submit a well site restoration report to the Department 60 days after restoration. When this report is submitted, the Department conducts an inspection to ensure that the restoration requirements have been met.

 This section largely restates the restoration requirements in section 3216 of the 2012 Oil and Gas Act and incorporates the Department's interpretation of these requirements as outlined in the Policy for Erosion and Sediment Control and Stormwater Management for Earth Disturbance Associated with Oil and Gas Exploration, Production, Processing, or Treatment Operations or Transmission Facilities, Commonwealth of Pennsylvania, Department of Environmental Protection, No. 800-2100-008, which was finalized on December 29, 2012. It is unreasonable to interpret the restoration requirements in the 2012 Oil and Gas Act to require restoration of the well site to a different standard depending upon whether or not a restoration extension has been granted. The Department included the phrase ''to the extent practicable'' in the definition of ''approximate original conditions'' in § 78a.1 in recognition of the fact that restoration to original contours may not always be feasible. Section 78a.65(a)(1) allows operators broad discretion to ensure wells and well sites can be operated safely while also complying with the site restoration requirements in the 2012 Oil and Gas Act.

Restoration timeline/2-year extension

 The restoration time frame is consistent with requirements in the 2012 Oil and Gas Act. Operators may request an extension of the restoration time frame because the extension will result in less earth disturbance, increased water reuse or more efficient development of the resources, or if restoration cannot be achieved due to adverse weather conditions or a lack of essential fuel, equipment or labor.

 For post-drilling, this final-form rulemaking requires restoration of the well site within 9 months after completion of drilling of all permitted wells on the site or within 9 months of the expiration of all existing well permits on the site, whichever is later. For post-plugging, it requires restoration within 9 months after plugging the final well on a well site. The restoration time frames are consistent with requirements in the 2012 Oil and Gas Act.

 Currently, a well site shall be restored within 30 days after expiration of the drilling permit, if the site is constructed and the well is not drilled. This was originally retained in the draft final-form regulations. Several comments were received from operators arguing this to be a burdensome requirement. While this may have been an appropriate time frame to restore a conventional well site, the size of an unconventional well site makes it very difficult to achieve this restoration time frame. The Department recognizes this and has changed the time frame to 9 months to be consistent with other restoration requirements.

 Some operator's comments expressed concern that restoration within 9 months may not work in every situation. Under this final-form rulemaking, operators may request an extension of the restoration time frame because the extension will result in less earth disturbance, increased water reuse or more efficient development of the resources or if restoration cannot be achieved due to adverse weather conditions or a lack of essential fuel, equipment or labor. This allows the operator some flexibility while still being protective of public health and safety and the environment.

PCSM requirements

 The amendments to § 78a.65 in the draft final-form regulations addressed comments on this section that expressed continuing confusion regarding what constitutes ''restoration'' as the term is used in Chapters 78 and 102, and what the associated requirements are. The changes to this section in this final-form rulemaking clarify these issues and, in particular, distinguish between areas not restored and other areas. ''Areas not restored'' do not fall within the provisions in § 102.8(n) and therefore must meet the requirements, among others, of § 102.8(g). Areas not restored include areas where there are permanent structures or impervious surfaces, therefore runoff produced from these areas must be tributary to permanent PCSM BMPs to ensure the runoff will be managed in accordance with the requirements of § 102.8.

Landowner consent for storing equipment not needed for production (agreements versus lease)

 Drilling supplies and equipment not needed for production may only be stored on the well site if written consent of the landowner is obtained. Several operators expressed concern that this requirement should not be necessary if they have an executed lease with the landowner allowing for the storage of equipment. The Department disagrees as the need for landowner consent is consistent with the requirements in section 3216 of the 2012 Oil and Gas Act. The requirement for consent allows the landowner to know what is being stored on their property, where a blanket allowance under a lease agreement may not afford transparency.

Waste disposal information in restoration report

 The Department acknowledges that the current waste reporting requirements may capture some of the same information required on the restoration report but still believes that waste disposal information should be included in the site restoration report. Details regarding the type of waste, as well as volume, leachate analysis and physical location are not captured in the waste reporting requirements. This information is critical for the landowner to be aware of where waste is located so it can be avoided in the event of future earth moving activities on the landowner's property.

§ 78a.66. Reporting and remediating spills and releases

 Spills or releases from containment of regulated substances at oil and gas well sites pose a substantial risk to the environment and public health, including impacts to water resources. Oil and gas operators of both conventional and unconventional wells have an obligation to report and properly remediate spills and releases in a timely manner.

 Several commentators felt that it was inappropriate to require cleanups of spills and releases under Act 2 because the 2012 Oil and Gas Act is not one of the environmental statutes referenced in Act 2. Act 2 provides a procedure to remediate and receive relief of environmental liability regarding a release of a regulated substance addressed under various environmental statutes, including The Clean Streams Law, the SWMA and the Hazardous Sites Cleanup Act (35 P.S. §§ 6020.101—6020.1305). Many substances that are spilled at sites regulated under the 2012 Oil and Gas Act are regulated as waste under the SWMA or as pollutants under The Clean Streams Law (see, for example, section 3273 of the 2012 Oil and Gas Act (relating to effect on department authority) and section 3273.1 of the 2012 Oil and Gas Act). If these wastes and pollutants are regulated substances as defined under Act 2 and have contaminated soils and groundwater, they must be addressed under Act 2, regardless of the nature of the activity that resulted in contamination.

 Some commentators felt that reporting requirements in § 78a.66(b)(2) went beyond the scope of what is required in § 91.33. The Department believes that subsection (b)(2) in this final-form rulemaking will serve as guidance for the responsible party to provide enough information, to the extent known, necessary for the Department to properly assess the reported spill incident, so the appropriate initial response can be employed by the Department.

 Many commentators were concerned that the public and other government agencies were not made aware of all spills and releases that occur at unconventional well sites. The regulations require that operators report releases within 2 hours of discovery to the Department electronically through its web site. This information will then be loaded directly into a spill and release database. The Department will utilize this database to create an electronic spill and release reporting and tracking system available for the public and government entities to receive up-to-date information concerning spills and releases and remedial actions at oil and gas operations. The system will be similar to the Department's eNOTICE system, which allows users to get information about their communities and the facilities they are interested in delivered directly by e-mail.

 Section 78a.66 cross-references § 91.33, which requires the operator or other responsible party to take necessary corrective actions, upon discovery of the spill or release, to prevent the substance from polluting or threatening to pollute the waters of the Commonwealth, damage to property or impacts to downstream users of waters of the Commonwealth. This concern was expressed in numerous comments over the possible pollution of private water wells due to oil and gas activity. To help address this, the operator or other responsible party will be required to identify water supplies that have been polluted or for which there is potential for pollution as a result of a spill or release at a conventional or unconventional well site. If a water supply is determined to have been polluted, it shall be restored or replaced in accordance with § 78a.51.

 The spill or release area shall then be remediated appropriately through Act 2 standards and processes. One of the primary reasons the Department requires remediation of spills to an Act 2 standard is because the operator is typically not the owner of the land where the regulated substance is spilled or released. It is simply unreasonable to leave behind contaminants at levels that may pose a health risk as a result of oil and gas operations on another person's property.

 The Department's Act 2 standards explicitly reflect the risks various compounds and elements pose to human health and the environment, and have been applied successfully to thousands of successful remediation projects over the past 19 years. This final-form rulemaking specifically provides flexibility to oil and gas operators to address small spills and releases, fully-contained releases and larger spills and releases in a flexible and straightforward manner.

 Several commentators raised issues with the ''alternative process'' included in the proposed rulemaking, which allowed operators to meet an Act 2 standard without necessarily following the notice and review provisions under Act 2. In response to those comments, the Department deleted the alterative process from this final-form rulemaking. All cleanups will either be small enough to address through excavation or follow the process outlined in these sections and Act 2.

 There were a few comments from operators who expressed concern over time constraints of report submittals that are in § 78a.66 for various portions of the remediation process. It is both reasonable and appropriate to require operators to carry out remedial actions promptly and not let contamination linger in the environment. The time frames established in this final-form rulemaking are modeled on the time frames established for corrective actions for releases from storage tanks in Chapter 245. The storage tank corrective action process was established in 1993 and has been used successfully for thousands of storage tank cleanups, both before and after the passage of Act 2 in 1995. The tank regulations were updated in 2001 to harmonize the regulations with Act 2 and the Act 2 implementing regulations in Chapter 250 (relating to administration of Land Recycling Program). These time frames are appropriate and have built-in flexibility to address the unique considerations posed by each remedial site. Finally, the Department notes that the time frames establish requirements for the steps that will lead to completion of the corrective action but do not establish a time frame by which demonstration of attainment of an Act 2 standard must be made. The Department recognizes that each site poses unique challenges and a one-size-fits-all completion date requirement is not appropriate.

§ 78a.67. Borrow pits

 As a result of concerns that the requirement to restore a borrow pit within 30 days of well permit expiration was impractical, the Department revised the restoration requirements in § 78a.67 to require borrow pits to be restored 9 months after completion of drilling the final well on a well site serviced by the borrow pit instead of 9 months after completion of drilling all permitted wells on the well site or 30 calendar days after the expiration of all existing well permits on well sites. This is in accordance with other restoration requirements that were similarly addressed in §§ 78a.59a and 78a.65. The main concern is the fact that an activity may be finished after the growing season, in fall or winter and will not be able to achieve any vegetative growth for stabilization until the next growing season. The Department believes 9 months is a reasonable time frame to ensure the operator has an opportunity to achieve this requirement.

 § 78a.68. Oil and gas gathering pipelines

 This final-form rulemaking requires the use of highly visible flagging, markers or signs to be used to identify the shared boundaries of the limit of disturbance, wetlands and locations of threatened or endangered species habitat prior to land clearing. The Department received comments for and against these provisions. The Department believes it is vital to delineate special area boundaries in the field, that is, limit of disturbance, jurisdictional streams and wetlands as well as endangered species habitat otherwise unseen or not readily visible to the untrained eye, to reduce the likelihood of unintentional disturbance during clearing and grubbing or other earthmoving activities. The Department considered not requiring these sensitive areas to be clearly marked in the field during oil and gas operations. However, the Department determined that the risk of damage to sensitive areas not easily seen from large earthmoving equipment and straying beyond the permitted limit of disturbance is too great to not include this provision in this final-form rulemaking. This requirement will greatly reduce potential impacts to these resources and it not only benefits any resources that are not impacted it also benefits any permittee that may have impacted these resources inadvertently and become subject to a compliance and enforcement case by the Department. Therefore, this is the least burdensome, acceptable alternative.

 This final-form rulemaking protects topsoil by requiring segregation of topsoil and subsoil during its excavation, storage and backfilling. The Department considered not requiring topsoil segregation because a number of comments were submitted suggesting this requirement should be deleted from this final-form rulemaking. However, the Department determined that the negative effects of not segregating topsoil would exceed the benefits of keeping this requirement and, therefore, this is the least burdensome yet acceptable alternative. Segregation of topsoil in all areas and phases is critical to successful restoration of pipeline right of ways. The practice of segregating topsoil favors industry by reducing the need, cost and the additional impact from importing topsoil to restore healthy vegetation after construction to establish permanent stabilization.

 This final-form rulemaking requires native and imported topsoil used for pipeline right of way restoration must be of equal or greater quality of the original topsoil to ensure the land is capable of supporting the uses that existed prior to earth disturbance. Some comments were against allowing any importation of topsoil. The Department considered not requiring importation of topsoil; however, this is the least burdensome yet acceptable alternative because topsoil used for restoring the pipeline right of way is of a quality capable of supporting the preexisting uses of the land.

 This final-form rulemaking requires that equipment refueling and staging areas must be out of floodways and at least 50 feet away from a body of water. The proposed setback for refueling and material staging areas from water bodies is appropriate and consistent with other regulatory requirements in Chapter 105. Commentators stated that the Department should allow for exceptions to the 50-foot distance restriction for material staging areas. The Department agreed and, as a result, § 78a.68(f) (relating to oil and gas gathering pipelines) has been amended to allow for materials staging within the floodway or within 50 feet of a water body if first approved in writing by the Department. Due to the consideration and allowance for exceptions, with prior approved by the Department in writing, the Department believes this is the least burdensome, acceptable alternative.

 This final-form rulemaking requires all buried metallic gathering pipelines to be installed and placed in accordance with 49 CFR Part 192, Subpart I or Part 195, Subpart H. Some comments received questioned the Department's statutory authority to incorporate Federal standards for pipelines into the rulemaking. Section 3218.4(a) of the 2012 Oil and Gas Act provides that ''[a]ll buried metallic pipelines shall be installed and placed in operation in accordance with 49 CFR Pt. 192 Subpt. I (relating to requirements for corrosion control).'' Section 78a.68(g) reflects this requirement. The incorporation of 49 CFR Part 195, Subpart H is included because that subpart also outlines standards for protecting pipelines against corrosion, specifically steel pipelines transporting hazardous liquids such as condensate from natural gas operations. The reference to 49 CFR Part 195, Subpart H is consistent with the intent of section 3218.4(a) of the 2012 Oil and Gas Act to set forth standards for the installation and placement of metallic pipelines, including related corrosion control requirements. Since it is imperative to ensure that buried metallic gathering lines do not leak and result in pollution, this is the least burdensome yet acceptable alternative, as no other known alternatives achieve the same assurance of the reduced likelihood of buried metallic gathering line pipes from leaking and it is a statutory requirement.

§ 78a.68a. Horizontal directional drilling for oil and gas pipelines

 This final-form rulemaking reinforces that HDD for oil and gas pipelines is subject to Chapters 102 and 105 and that certain requirements specific to this section must be met. The Department received many comments in favor of this language. The Department also received comments stating that the language in § 78a.68a is redundant since the activity is already regulated under Chapters 102 and 105. The Department considered not including language pertaining to HDD for oil and gas pipelines in Chapter 78; however, the intent of the section is to provide clarity to existing requirements and address issues that frequently arise during HDD activities conducted by the oil and gas industry. Therefore, this is the least burdensome, acceptable alternative.

 This final-form rulemaking includes a requirement for a PPC plan for HDD with a site-specific contingency plan that describes the measures to be taken to control, contain and collect any discharge of drilling fluids and minimize impacts to waters of the Commonwealth. The Department considered not including this requirement; however, due to the heightened potential for pollution to waters of the Commonwealth that HDD creates, a separate PPC plan is required for this specific activity. A separate PPC plan is not required for HDD activities provided that the PPC plan developed under § 78a.55 meets the requirements in section § 78a.68a.

 HDD activities over and adjacent to bodies of water and watercourses shall be monitored for any signs of drilling fluid discharges as required in this final-form rulemaking. Many inadvertent returns of HDD fluids express themselves hundreds of feet from the actual bore hole. Therefore, monitoring bodies of water and watercourses during HDD activities will detect impacts as soon as they occur. The Department considered not including this requirement; however, the alternative would be to not monitor for inadvertent returns which would present a significant opportunity for these instances to pollute waters of the Commonwealth without effectively seeking a solution to the problem. Therefore, this requirement is the least burdensome, acceptable alternative.

 This final-form rulemaking includes a requirement to immediately notify the Department of an HDD drilling fluid discharge or loss of drilling fluid circulation. This is consistent with the reporting requirements in § 91.33 which is the least burdensome, acceptable alternative because this final-form rulemaking cannot be less stringent than this requirement.

 HDD drilling fluid additives other than bentonite and water must be approved by the Department prior to use. All approved HDD fluid additives will be listed on the Department's web site to eliminate the need for preapproval prior to each use. This will ensure that HDD operators know which additives are preapproved for use without having to wait for the Department to review and approve a drilling additive. The Department considered not including this requirement; however, the Department believes this is the least burdensome, acceptable alternative because it should not be considered overly burdensome for operators to check the list provided by the Department to determine acceptable substances to be used for this activity.

§ 78a.68b. Well development pipelines for oil and gas operations

 Well development pipelines that transport flowback water and other wastewaters shall be installed aboveground, as required in this final-form rulemaking. The Department received comments saying that the Department should allow all well development pipelines to be buried. The Department considered not including this requirement, but determined this is the least burdensome, acceptable alternative because buried pipelines cannot be easily inspected for leaks or damage while aboveground pipelines can be visually inspected daily when in use and if leaks or defects are observed, repairs or other effective corrective measures can be taken expeditiously, thereby reducing or avoiding the impact of an accidental pollutional event. Under the definition of ''well development pipeline'' in § 78a.1, if a pipeline is not used solely to move wastewater (for example, as a low-pressure gathering line) or the pipeline does not lose its utility after the well site it serviced has been restored under § 78a.65, then it does not meet the definition and does not need to meet the requirements of this section.

 This final-form rulemaking specifies that well development pipelines may not be installed through existing stream culverts, storm drain pipes or under bridges that cross streams without approval by the Department under § 105.151. The Department received comments against this requirement. The Department considered not including this requirement, but determined this is the least burdensome, acceptable alternative because most culverts, storm drains and bridges that cross streams are designed and sized taking the maximum anticipated flow of water into consideration. Placing well development pipelines in/under them displaces their capacity to carry their designed load, which could lead to localized flooding as a result.

 This final-form rulemaking requires certain safety measures with well development pipelines used to transport fluids other than fresh ground water, surface water and water from water purveyors or approved sources. These pipelines shall be pressure tested prior to being placed into service and after the pipeline is moved, repaired or altered. They must have shut off valves, check valves or other methods of segmenting the pipeline placed at designated intervals that prevent the discharge of more than 1,000 barrels of fluid. They may not have joints or couplings on segments that cross waterways unless secondary containment is provided. They cannot be used to transport flammable materials. The STRONGER organization recommends that state programs should address the integrity of pipelines for transporting and managing hydraulic fracturing fluids off the well pad. The Department received comments that endorsed these provisions and comments that were against their implementation. The Department considered not including these requirements; however, the Department believes this is the least burdensome, acceptable alternative because these safety measures are necessary to protect the environment by providing mechanisms that help identify their locations, isolate sections that are compromised, minimizes direct leaks into waterways and eliminates the risk of fires. Without these requirements there would be many more opportunities for pollution to occur to waters of the Commonwealth than if they are kept in this final-form rulemaking.

 This final-form rulemaking requires well development pipelines to be removed when the well site is restored. The Department received comments requesting that these pipelines should be allowed to remain to transport and reuse production water from the well site. Well development pipelines are meant to be temporary and used for the sole purpose of well development activities at a well site. Well development pipelines need to be removed when the well site get restored in accordance with § 78a.65. The Department considered not including this requirement, however, permanent pipelines used for transportation of fluids are beyond the scope of this final-form rulemaking.

 This final-form rulemaking requires the operator to maintain certain records regarding well development pipelines, including their location, type of fluids transported, the approximate time of installation, pressure test results, defects and repairs. The records need to be retained for 1 year after their removal and be made available to the Department upon request. The Department received a comment that well development records should be retained by operators for 2 years after their removal. The Department believes 1 year is a sufficient amount of time for record retention due to the temporary nature of these pipelines. The Department considered the additional year of record retention but determined that there was not a significant benefit to this, therefore the requirement in the rulemaking is the least burdensome, acceptable alternative.

 This final-form rulemaking requires operators to obtain Department approval for well development pipelines in service for more than 1 year. The Department believes that a well development pipeline that is in service for over 1 year becomes more than a temporary use and wants to know about its location and use.

§ 78a.69. Water management plans

 Commentators urged the Department to include conventional operations in the requirement to develop WMPs. WMPs are a requirement of section 3211(m) of the 2012 Oil and Gas Act, which by its terms only applies to unconventional wells. This section codifies existing requirements to protect quality and quantity of water sources in the Commonwealth, including freshwater resources, from adverse impacts to the watershed considered as a whole from potentially inappropriate withdrawals of water. This final-form rulemaking mirrors most of the requirements of the Susquehanna River Basin Commission and the Delaware River Basin Commission to ensure that requirements are consistent Statewide, regardless of from which river basin an operator withdraws water. This section of this final-form rulemaking only applies to unconventional operations. The Department does not believe that the scope of water use by the conventional oil and gas industry warrants a requirement to develop WMPs as a matter of regulation. If a conventional operator will be employing high-volume slickwater hydraulic fracturing to develop a well, the Department may require a WMP as a permit condition to meet the obligations under The Clean Streams Law to protect the waters of the Commonwealth.

§ 78a.70. Road-spreading of brine for dust control and road stabilization

 Commentators recommended the complete prohibition of spreading of brine on roads for dust control. The Department considered a complete prohibition of the road spreading of brine and determined that unconventional brines may not be spread on roads for any reason. This section was amended in this final-form rulemaking to clearly ban the use of brines and produced fluids from unconventional wells for dust control and road stabilization.

§ 78a.70a. Pre-wetting, anti-icing and de-icing

 Commentators recommended the complete prohibition of brine being used to de-ice roads. The Department considered a complete prohibition of the road spreading of brine for pre-wetting, anti-icing and de-icing and determined that unconventional brines may not be spread on roads for any reason. This section was amended in this final-form rulemaking to clearly ban the use of brines and produced fluids from unconventional wells for pre-wetting, anti-icing and de-icing.

§ 78.121. Production reporting

§ 78a.121. Production reporting

 This final-form rulemaking requires unconventional operators to report their waste production on a monthly basis within 45 days of the end of the month. The Department received significant comments on this provision from unconventional operators. Operators noted that the act of October 22, 2014 (P.L. 2853, No. 173) (Act 173) which required monthly production reporting did not include waste reporting within its scope and therefore inclusion of this requirement is inappropriate. The monthly waste reporting requirement under § 78a.121(b) (relating to production reporting) is not reliant on Act 173, therefore the legislative intent of Act 173 is not relevant to § 78a.121(b). The statutory authority for § 78a.121(b) is under provisions of the SWMA, particularly section 608(2) of the SWMA (35 P.S. § 6018.608(2)), which requires that the Department shall ''[r]equire any person or municipality engaged in the storage, transportation, processing, treatment, beneficial use or disposal of any solid waste to establish and maintain such records and make such reports and furnish such information as the department may prescribe.''

 Monthly waste reporting is not due until 45 days after the end of the month in which waste was generated and managed. This should provide sufficient time for operators to receive and compile the information necessary to provide a monthly waste production report to the Department.

 The Department also disagrees with the characterization of extra burden posed by more frequent reporting. While the data shall be gathered more frequently, the current data reporting requirements would still require the operator to compile and report the same data at the end of the 6-month period. Operators shall account for and report all wastes generated in the 6-month period already, the only end difference in terms of overall reporting should be that the Department would possess data segregated by month after October 8, 2016. The end totals of waste generated and facilities where that waste was managed should be exactly the same at the end of the term as it is today.

 Data analyses conducted by the Department, which compared 2013 and 2014 calendar year records from facilities that receive oil and gas waste for processing or disposal and from data reported by oil and gas operators in the Department's oil and gas electronic reporting database, revealed that there are significant discrepancies in both the quantities of waste reported by oil and gas operators and also in the way the wastes are classified. More recent analyses have indicated that oil and gas operator reporting is improving; however, the same issues still exist. The current biannual reporting requirement is not conducive to correcting reporting discrepancies because the Department does not become aware of a reporting issue until a substantial amount of time has passed from when the waste was originally sent for processing or disposal. Monthly reporting promotes quicker recognition of reporting inaccuracies that can be rectified in a more reasonable time frame.

 The Department believes that the monthly time frame with reporting due 45 days after the end of the month is clearly feasible for operators. Because the current 6-month reporting requirement includes data from June in the August report and December in the February report, operators are already compiling 2 months reporting data in that 45-day window or they are out of compliance with the current regulation.

 Commentators also argued that this new provision singles out the oil and gas industry with overly burdensome requirements that are not applied to other industries. The Department disagrees. The Department believes that responsible operators are aware of and track their waste generation, transportation, treatment, storage and disposal, and operating without awareness is not a BMP and is unacceptable in this Commonwealth. As a final note, the Department believes that the monthly reporting requirement strikes the appropriate balance between burden and benefit compared to other regulatory alternatives, such as keeping the current flawed 6-month reporting system or imposing a load-by-load manifest system as is currently required for hazardous wastes.

 In this final-form rulemaking, § 78.121(a) is amended to delete reporting requirements for unconventional wells. The final sentence of the existing section as carried over to this final-form rulemaking, regarding electronic reporting of production data, is renumbered as subsection (b). These changes were retained because they solely affected unconventional wells.

§ 78a.122. Well record and completion report

 The primary amendment to this section relates to area of review requirements. The certification by the operator that the monitoring plan required under § 78a.52a was conducted as outlined in the area of review report was moved from the well record to the well completion report. This amendment is appropriate given that monitoring occurs during hydraulic fracturing of the well as opposed to drilling, so the completion report is the proper report to contain this certification.

 The Department received several comments requesting clarification of when a well is ''complete,'' as the completion report is due within 30 days of completion of the well, when the well is capable of production. A well is ''capable of production'' after ''completion of the well.'' Section 3203 of the 2012 Oil and Gas Act (relating to definitions) defines ''completion of a well'' as ''[t]he date after treatment, if any, that the well is properly equipped for production of oil or gas, or, if the well is dry, the date that the well is abandoned.'' The Department considers a well to be ''properly equipped for production of oil or gas'' under the following circumstances:

 For wells not intended to have the producing interval cased or stimulated prior to production (that is, natural wells), the well is properly equipped for production when the well has been drilled to total depth.

 For wells intended to have the producing interval cased, but not stimulated, prior to production, the well is properly equipped for production when the last perforation is placed.

 For wells intended to be stimulated prior to production, the well is properly equipped for production upon commencement of flow back.

§ 78a.123. Logs and additional data

 This section requires the submission of three types of information—standard drilling logs, specialty information and specific requests for additional data to be collected during drilling. After reviewing section 3222 of the 2012 Oil and Gas Act, the Department clarified in subsections (a) and (d) in this final-form rulemaking. The most significant change is that the Department is requiring submission of standard drilling logs for all wells in subsection (a), rather than requesting the logs for each individual well site when permits are issued.

 The comments received on this section mainly concerned the confidentiality of logs submitted under subsection (a) and the time frames for submission and the perceived time frames for submission under section 3222 of the 2012 Oil and Gas Act. Section 3222(d) of the 2012 Oil and Gas Act states:

Data required under subsection (b)(5) and drill cuttings required under subsection (c) shall be retained by the well operator and filed with the department no more than three years after completion of the well. Upon request, the department shall extend the deadline up to five years from the date of completion of the well.

 Subsection (a) of this final-form rulemaking requires submittal of electrical, radioactive and other standard industry logs within 90 days of completion of drilling. Those logs are referenced in section 3222(b)(4) of the 2012 Oil and Gas Act, and so are not subject to section 3222(d) of the 2012 Oil and Gas Act. This final-form rulemaking retains the 3-year and 5-year periods in section 3222(d) of the 2012 Oil and Gas Act for information in section 3222(b)(5) and (c) of the 2012 Oil and Gas Act. The Department believes that data confidentiality is already preserved for an adequate period of time based on the existing language of 2012 Oil and Gas Act.

 All comments received on the proposed rulemaking and related issues have been addressed in this final-form rulemaking.

G. Benefits, Costs and Compliance

Benefits

 The residents of this Commonwealth and the regulated community will benefit from this final-form rulemaking. The process for identifying and considering the impacts to public resources will ensure that any probable harmful impacts to public resources will be avoided or mitigated while providing for the optimal development of natural gas resources. The regulations that require operators to conduct an area of review survey and appropriately monitor wells with the risk of being impacted by hydraulic fracturing activities will minimize potential impacts to waters of the Commonwealth. The containment systems and practices requirements for unconventional well sites will minimize spills and releases of regulated substances at well sites and ensure that any spills or releases are properly contained. The amendments to the reporting and remediation requirements for releases will ensure Statewide consistency for reporting and remediating spills and releases.

 New planning, notification, construction, operation, testing and monitoring requirements for pits, tanks, modular aboveground storage structures, well development impoundments and pipelines will help prevent releases or spills that may otherwise result without these additional precautions. Additionally, the monitoring and fencing requirements for pits and impoundments and unconventional tank valve and access lid requirements for tanks ensure protection from unauthorized acts of third parties and damage from wildlife. Further, the requirements regarding wastewater processing at well sites will encourage the beneficial use of wastewater for drilling and hydraulic fracturing activities.

 This final-form rulemaking contains several new notification requirements which will enable Department staff to effectively and efficiently coordinate inspections at critical stages of modular aboveground storage facility installation, onsite residual waste processing and HDD activities. Additionally, requiring electronic submission for well permits, notifications and predrill surveys will enhance efficiency for both the industry and the Department. As new areas of this Commonwealth are developed for natural gas, the regulations will avoid many potential health, safety and environmental issues as well as provide a consistent and efficient approach to natural gas development in this Commonwealth.

Compliance costs

Unconventional operators' costs

Assumptions

 When initially proposing this final-form rulemaking, the Department estimated based on data available at the time that there will be approximately 2,600 unconventional wells permitted each year for the next 3 years.

 On average, about one of every two permitted unconventional wells are drilled.

 In addition, the Department estimated that there were an average of three unconventional wells per well site.

 Since considerable time has passed since the proposed rulemaking was published, the Department was able re-evaluate the rate at which unconventional wells are permitted and drilled in this Commonwealth and include data for 2013, 2014 and the first three quarters of 2015.

 The Department's records also show that there are currently 3,387 unconventional well pads with at least 1 well drilled and a total of 9,486 total unconventional wells located within this Commonwealth. This equates to an average of 2.8 wells per pad. In the future, it is estimated that less well sites will be built as there could be as many as 22 wells on a pad, based on data available to the Department.

 The cost analysis for this final-form rulemaking must be factored on a well site basis, not on a per well basis. Many of the processes proposed for regulation in this final-form rulemaking include activities integral to the operation of several wells and even several well pads.

Year	Unconventional Wells Permitted	Unconventional Wells Drilled
2010	3,364	1,599
2011	3,560	1,960
2012	2,649	1,351
2013	2,965	1,207
2014	3,182	1,327
2015*	1,919*	756*

 *Data extrapolated from first 3 quarters (1,439 wells permitted, 567 wells drilled as of September 8, 2015)

 Based on the data shown in the previous table which represents the most recent 5-year period, it is clear that the Department's estimate was relatively accurate. The number of wells permitted exceeded the Department's estimate but the percentage of permitted wells that have been drilled is approximately 46% since 2010 and 41% since 2013, which is lower than the Department's original estimate. The Department does not believe that the new data supports a change to its original estimate of 2,600 wells permitted per year and 1,300 wells drilled per year as a reasonable conservative estimate of the potential unconventional well drilling activity over the next 3 years.

 The Department believes that the number of unconventional wells per well site will rise in time but has retained the estimate of three wells per well site for the purposes of this estimate because it is reflective of current conditions and what is expected over the next 3 years.

 2,600 wells permitted × 50% of wells drilled = 1,300 wells drilled each year

 1,300 wells drilled each year ÷ 3 wells per well site = 434 well sites built each year

Cost estimates

 The Department reached out to oil and gas operators, subcontractors and industry groups to derive the cost estimates of this final-form rulemaking.

Identification of public resources (§ 78a.15)

 The requirements in this section ensure that the Department meets its constitutional and statutory obligations to protect public resources.

 The Department received significant public comment on these provisions from unconventional gas well operators regarding the cost of implementing the public resource screening process requirements in § 78a.15(f) and (g). Commentators disagreed with the Department's estimates of cost for permit conditions mitigation measure to protect public resources. Commentators also argued that there will be considerable expenses related to personnel time, expert consultants needed for surveys and project delays in associated with the responses from public resource agencies. The Department acknowledges that there is some cost associated with implementing these requirements. The total cost of this provision will vary on a case-by-case basis. This cost is dependent on several variables including, the number of well sites that are within the prescribed distances or areas listed, the type and scope of operations within prescribed distances or areas, the type of public resource, the functions and uses of the public resource, specific probable harmful impacts encountered and several other variables and the available mitigation measure to avoid, mitigate or otherwise minimize impacts. Because so many significant variables exist, the cost estimate for implementation of the entire provision will vary. For that reason, the Department provides the following estimate for specific steps which allow for an estimate to be made.

 The first step in the process is identification. The Department believes this process would be required for all new well sites. First an electronic review can be conducted with the Pennsylvania Conservation Explorer's online planning tool. This tool will allow operators to identify the location of the majority of public resources which require consideration under this final-form rulemaking. This tool also will allow the operator to identify potential impacts to threatened and endangered species, which also must be addressed under § 78a.15(d). Since the tool may not have data to identify all the public resources listed in § 78a.15(f)(1), operators will also need to conduct a field survey of the proposed well site area to identify public resources. This field survey will likely include identification of schools and playgrounds 200 feet from the limit of disturbance of the well site. The Department estimates the cost of this field survey to be $2,000 and the cost of the electronic survey to be $40. Even though use of the online tool is currently required to comply with requirements protecting threatened and endangered species, the Department has included the cost in this estimate nonetheless.

 $2,000 × 434 = $868,000

 $40 × 434 = $17,360

 $868,000 + $17,360 = $885,360

 The second step of the process is consultation with the public resource agency. This process is only applicable to well sites which are within the prescribed distances or areas listed in § 78a.15(f)(1). The Department estimates that 30% of well sites will fall within these distances or areas. Operators will be required evaluate the functions and uses of the public resource, determine any probable harmful impacts to the public resource and develop any needed mitigation measures to avoid probable harmful impact. Operators shall also notify potentially impacted pubic resource agencies of the impact and provide those public resource agencies the same information provided to the Department. Cost of the provision is dependent on the number of well sites impacted as well as the complexity of evaluating the functions and uses of the public resource. The Department estimates the postage will cost $20 per notification to public resource agencies.

 $20 × 434 × 30% = $2,604

 Due to the complexity of the variables in this process, the estimate for the cost of evaluating the functions and uses of the public resource and determining whether there is a probable harmful impact will vary. In some cases, functions and uses of the public resource and any probable harmful impacts may be immediately obvious and others may be far more complex and may include multiple public resources.

 The final step in the process is mitigation. The cost estimate for mitigation will vary. In some circumstances, an operator may be able to plan the location of the well site using the planning tool previously discussed to avoid public resources resulting in zero cost. Any cost associated with mitigation measures is dependent on many variables and may be situation specific in some cases. While the Department is unable to provide a specific estimate for the implementation of this entire provision, it should be noted that this cost may be substantial depending on the location of the well site.

 $885,360 + $2,604 = $887,964

 The total cost of this provision is $887,964 (not including consultation and mitigation).

Protection of water supplies (§ 78a.51)

 This section provides the Department's interpretation of the water supply restoration and replacement in section 3218(a) of the 2012 Oil and Gas Act. This section seeks only to provide clarity to existing statutory requirements. Accordingly, the estimated new cost incurred by unconventional operators is $0.

 The total new cost of this provision is $0.

Area of review and monitoring plans (§§ 78a.52a and 78a.73)

 $8,720

 $8,720 × 1,300 wells = $11,336,000

 The total cost of this provision is $11,336,000.

 The Department's 2013 Regulatory Analysis estimated the compliance cost at $2,000 per new well. That Department estimate was made before the introduction of significant new requirements in 2015, including:

 • Researching the depth of identified wells.

 • Development of monitoring methods for identified wells, including visual monitoring under accompanying § 78.73 (relating to general provisions for well construction and operation).

 • Gathering surface evidence concerning the condition of identified wells.

 • Gathering GPS, that is, coordinate data for identified wells.

 • Introduction of a provision of advanced notice to adjacent operators under accompanying § 78.73.

 • The assembly of the previously listed data in an area of review report and monitoring plan and the submission of the report at least 30 days prior to the start of drilling the well at well sites where hydraulic fracturing activities are anticipated.

 With the additional items, the cost of compliance is expected to exceed $2,000 per well.

 However, it is important to emphasize that industry commentators have indicated the majority of the work required as part of the area of review is already performed by operators in an effort to not only reduce potential environmental liability, but also to protect the investment associated with the drilling and stimulation of a new well, which represents millions of dollars for a typical unconventional well.

 Further, it should be emphasized that the costs associated with the review of historical data will be negligible, as most unconventional companies already have subscriptions to well-location databases. EDWIN, which is one of the primary databases used for retrieving records related to oil and gas wells in this Commonwealth, costs $500 per year for a full subscription. For a company drilling 25 wells a year this results in a cost of $20 per well along with search and retrieval costs. Many other sources of information are free.

 Most unconventional companies hire professional engineering firms to complete surveying activities. Estimates for the generation of plats, which are already required for well drilling permits, are expected to range between $4,000 and $5,000, with an average cost of $4,600. These costs were gathered by speaking with companies that routinely perform this work for the unconventional industry. Assumptions include 2 days of field work and 1 day of office work to compile the data necessary for submission. It should be noted that current Commonwealth statutes only require that survey data be collected by a ''responsible surveyor or engineer,'' and that existing law under section 3213(a.1) of the 2012 Oil and Gas Act has required operators to identify all abandoned assets discovered on their leases to the Department for many years. It is noted that one company providing information did ask that the Department consider the additional burdens being placed on the industry and expressed concerns that more oil and gas activities would be shifting to neighboring states as a result of this final-form rulemaking. The individual had asked that limits be placed on offset wells requiring identification in the area of review (active only) and indicated that landowners in drilling units have reacted in a confrontational manner with members of his staff in the past.

 The Department has experience monitoring well vents in its plugging program. Costs are anticipated to remain under $500 per day per offset well; although the number of wells requiring continuous monitoring is not expected to be very high on a case-by-case basis, as monitoring candidates must not only penetrate the zone expected to be influenced by hydraulic fracturing, but also represent a high enough risk that continuous monitoring is deemed warranted. In many cases avoidance mitigation measures, plumbing a tank to the well of concern or inspecting offset well sites periodically may be all that is necessary. For at least a fraction of the wells drilled, no offset wells will penetrate the zone of concern and monitoring costs will be negligible. This cost item is expected to range from negligible amounts to a maximum of $7,500 per well site, with an average cost of $3,500.

 There are nominal costs associated with a certified mailing program that assumed 100 landowners are contacted in association with a well site at a cost of $6 per mailing.

 Although the Department contends that the work specified in this section of this final-form rulemaking is already being conducted by responsible unconventional operators in this Commonwealth and implementation will merely result in a marginal incremental cost for reporting, its cost analysis based on speaking with qualified professionals and its own experience contracting services in its well plugging program projects that total costs for an unconventional well operator employing standard industry practices could conceivably average around $9,000 per well site.

 For comparison, the Department recently analyzed costs associated with several unconventional well hydraulic fracturing communication incidents documented in this Commonwealth. The circumstances surrounding these incidents varied: two involved communications between a well that was being stimulated and a nearby well being drilled; another involved communication between two stimulated wells that had not been flowed back and a well that was being hydraulically fractured on the same pad; and the last involved communication with a previously unknown and inadequately plugged conventional well. Costs associated with unconventional wells tend to be derived from a more complicated set of variables that not only must factor in the equipment being used and subsequently placed on standby at the time of the incident (for example, costs range from $10,000 to $50,000 per day); but also lost revenues in association with delayed production and the need to meet gas-market commitments by established deadlines that may prompt reconfiguring existing well network flow-to-pipeline parameters or purchasing gas on the open market, or both. These costs are potentially further compounded by any environmental issues that shall be addressed (for example, water well sampling/monitoring and analytical costs and consultant costs for data analysis and interpretation), logging and downhole camera costs to inform any well work that shall be completed, plugging costs of any unconventional wells affected beyond repair and any improperly plugged legacy wells, material costs (for example, loss of drilling muds that are normally rented) and accelerated expenditures to prepare a new site. Cost estimates for the first two incidents ranged from $90,000 to $800,000. Total costs for the second scenario, which involved plugging two drilled unconventional wells that had not been brought back into production, are estimated at $13 million to $16 million. Total costs for the third scenario were in excess of $1 million. The Department acknowledges that in certain cases, even with the implementation of this final-form rulemaking and the application of best practices, that some percentage of communication incidents will still take place. However, it adds that this regulatory concept is being addressed and acknowledged by a number of other regulatory programs, the STRONGER organization and the American Petroleum Institute, a globally recognized industry trade organization. It is also significant to note that a single severe hydraulic fracturing communication incident is capable of exceeding the estimated annual cost of implementation for an entire unconventional industry.

Site-specific PPC plan (§ 78a.55)

 This final-form rulemaking requires all unconventional operators to develop and implement a site-specific PPC plan under § 78a.55. The Department received significant public comment from operators on this section. Commentators expressed concerns about § 78a.55(a) which simply reiterates the requirements already existing in §§ 91.34 and 102.5(l). Because § 78a.55(a) does not establish any new requirements, the Department does not believe that this subsection presents any new burden on operators and no cost was attributed with these provisions.

 The Department initially estimated that the new cost of this requirement would be between $86,800 and $130,200. Upon further evaluation, the Department revised this estimate. The requirement for operators to develop a control and disposal plan or PPC plan has been in existence under § 78.55 since 1989 when Chapter 78 was first adopted. A plan that does not address the specific needs of a site could not and should not be considered to meet the requirements of § 78.55. Therefore, for operators to ensure that they were in compliance with the planning requirements in § 78.55, they must have been evaluating their PPC or control and disposal plans against site-specific conditions since 1989. In addition, it is not the intent of this final-form rulemaking nor is it required under this final-form rulemaking that each PPC plan developed for a different well site must be unique. Therefore, the Department does not believe its initial estimates are accurate. Instead, the Department estimates the new cost associated with this requirement to be negligible because operators have been required to develop these plans since 1989.

 It is not the intent of this final-form rulemaking to ensure that all PPC plans are revised annually. There are no specific review and update time frames included in this final-form rulemaking. This final-form rulemaking requires revisions to the plan in the event that practices change. Therefore, if conditions at the site do not change, there will be no need to make revisions to the PPC plan. In addition, operators have been required to revise their plans under these same conditions since Chapter 78 was initially adopted in 1989. Therefore, there is no new cost attributed to this provision.

 Finally, this final-form rulemaking does not include a requirement that every single site where activities including the impoundment, production, processing, transportation, storage, use, application or disposal of pollutants shall have the PPC plan posted onsite at all times. This final-form rulemaking does not include this requirement or anything resembling this requirement. In fact, this final-form rulemaking does not require the PPC plan to be maintained on the site at all. The Department believes that it is prudent for operators to maintain the PPC plan on the site when the site is active, including drilling, alteration, plugging or other activities when there is an increased risk of a spill, release or other incident, but it is not required by § 78a.55. Therefore, there is no new cost attributed to this requirement.

 The total new cost of this provision is $0 (negligible).

Providing copies of the PPC plan to the Fish and Boat Commission and the landowner (§ 78a.55(f))

 This final-form rulemaking includes a requirement for operators to provide copies of the site-specific PPC plan to the Fish and Boat Commission and the landowner upon request. The cost associated with this requirement depends on the number of plans that are requested. If no plans are requested, there is no cost associated with this requirement. If the landowner and the Fish and Boat Commission request the plan for every well site, the Department estimates the cost to be $21,700.

 434 × $25 × 2 = $21,700.

 The total new annual cost of this provision is estimated to be $21,700.

Banning use of pits (§ 78a.56)

 This final-form rulemaking disallows the use of pits for temporary storage of waste at unconventional well sites. The Department does not believe that this provision will result in any significant cost because pits are rarely used for this purpose at unconventional well sites.

 This final-form rulemaking requires pits at unconventional well sites to be restored by April 8, 2017. The Department does not anticipate that this section will result in any significant new cost because pits are rarely used at unconventional well sites and because pits regulated under § 78.56 are already required to be restored within 9 months of completion of drilling of the well serviced by the site.

 The estimated new cost of this provision is $0.

Fencing around unconventional well site pits (§ 78a.56(a)(5))

 When initially proposed this paragraph required unconventional operators to install fencing around pits on well sites. This final-form rulemaking does not allow unconventional operators to utilized waste pits on their well site. Since this provision does not exist, there is not associated cost.

 The total cost of this provision is $0.

Determination of seasonal high groundwater table for pits and labor to inspect and test the integrity of the liner (§§ 78a.56(a) and 78a.62)

 When initially proposed these sections required unconventional operators to make a determination of the depth to seasonal high groundwater table and inspect liners for pits on well sites. This final-form rulemaking does not allow unconventional operators to utilized waste pits on their well site. Since this provision does not exist, there is not associated cost.

 The total cost of this provision is $0.

Tank valves and access lids equipped to prevent unauthorized access by third parties (§§ 78a.56(a)(7) and 78a.57(h))

 If the well site has 24-hour security presence, the operator satisfies the requirements of these sections. This calculation assumes that all well sites will not have 24-hour security. This should be a one-time expense as the protective measures will be affixed to the tanks. The Department estimates $7,000 for each well site.

 $7,000 × 434 = $3,038,000

 The total cost of this provision is $3,038,000.

Signage for tanks and other approved storage structures (§ 78a.56(a)(8))

 Unconventional operators will be required to display a sign on the storage structure identifying the contents and if any warnings exist, such as corrosive or flammable.

 The cost of this regulatory requirement depends on the number of tanks/storage structures and the types of signage used. The Department assumes that the cost can be in the range of $250—$2,000 for each well site.

 $250 × 434 = $108,500

 $2,000 × 434 = $868,000

 The total cost of this provision is between $108,500 and $868,000.

Vapor controls for condensate tanks (§ 78a.56(a)(10))

 Vapors must be controlled at all condensate tanks. Based on Department inspection experience, this calculation assumes that only 40% of well sites will have condensate tanks. The Department estimates $12,500 for each well site.

 $12,500 × (434 × 40%) = $2,170,000

 The total cost of this provision is $2,170,000.

Secondary containment for all aboveground structures holding brine or other fluids (§ 78a.57(c))

 The cost of this subsection depends on the number of aboveground structures on each well site.

 The Department assumes that the cost can be in the range of $5,000—$10,000 for each well site.

 $5,000 × 434 = $2,170,000

 $10,000 × 434 = $4,340,000

 The total cost of this provision is between $2,170,000 and $4,340,000.

Identification of existing underground/partially buried storage tanks and registration of new underground/ partially buried storage tanks (§ 78a.57(e))

 When initially proposed, this subsection prohibited the use of underground or partially buried storage tanks for storing brine and operators would have 3 years to remove all existing underground or partially buried tanks. The Department's initial cost estimate did not attribute a cost to this subsection because the cost was dependent on the number of buried tanks across this Commonwealth and the Department was unable to estimate the number of buried tanks at that time. As a result of public comment, the Department amended this final-form rulemaking to allow the use of buried tanks by both conventional and unconventional well site operators and does not require removal of existing buried tanks. The Department continues to believe that underground storage tanks warrant extra scrutiny because they are not as easily inspected and can provide a more direct conduit for contamination into groundwater and therefore has included provisions in this final-form rulemaking to require the location of all existing and any new underground storage tanks at well sites to be reported to the Department. Therefore, the original estimate of $20,000 is retained. The Department does not believe that there will be any significant new cost associated with notifying the Department of newly installed underground or partially buried tanks.

 The total cost of this provision is estimated to be $20,000.

Corrosion protection for permanent aboveground and underground tanks (§ 78a.57(f) and (g))

 Section 78a.57(f) and (g) implements section 3218.4(b) of the 2012 Oil and Gas Act which establishes that permanent aboveground and underground tanks must comply with the applicable corrosion control requirements in the Department's storage tank regulations.

 It is common knowledge that steel structures, including storage tanks, corrode or rust and fail when left unprotected and exposed to the elements. It is also common knowledge that brine or salt water which is commonly stored in tanks at conventional well sites increases the rate of corrosion of steel. Given these facts and considering that the estimated cost for replacement tanks is significantly higher than the estimated cost for providing corrosion protection for those same tanks (see the following table; the estimated costs for providing corrosion protection is less than half the cost of a new tank), the Department believes that it would behoove gas operators to provide corrosion protection for their tanks because it can extend the useful life of the tank significantly at a fraction of the cost of replacing the tank. In fact, this provision may represent a cost savings to operators that had previously not been maintaining their tanks appropriately.

Size (bbl)	Current Cost	Cathodic Protection	Corrosion Protection Protection	Ratio of Cost of Corrosion Protection to Replacement
25 bbl	$1,800	$350	$450	0.44
50 bbl	$2,200	$350	$650	0.45
100 bbl	$3,451	$350	$1,200	0.45
140 bbl	$5,144	$350	$1,300	0.32
210 bbl	$6,083	$350	$1,600	0.47

 Finally, this requirement is a statutory requirement under section 3218.4(b) of the 2012 Oil and Gas Act. As previously noted, § 78a.57(f) and (g) simply implements this requirement. The Department has also explicitly deleted the requirement to use Department certified inspectors to conduct inspections of interior linings or coatings which will alleviate some burden on oil and gas operators. Operators may choose to use nonmetallic tanks which can often be less expensive than steel equivalent and do not require any additional cost to ensure protection from corrosion.

 Since this section implements existing statutory requirements, no cost is assigned to this provision.

 The estimated new cost of this provision is $0.

Monthly maintenance inspection (§ 78a.57(i))

 Section 78a.57 imposes a new requirement for operators to conduct periodic inspections of tanks used to control and store production fluids on a well site and document each inspection. The monthly maintenance inspection is intended to be a visual check of the tank and containment area to ensure that the tank and containment structures are in good working condition and that ancillary and safety equipment are in place and in good working condition. The Department estimates that on average inspection of each tank, including filling out the inspection form, will take 15 minutes. When initially proposed this provision required use of forms provided by the Department but in response to comments the provision was revised to allow operator generated forms. The Department will provide a form for use by operators that prefer to use the Department's form or do not have their own inspection documentation.

 The Department estimates that the unconventional industry utilizes approximately 30,000 tanks. With a labor rate of $30/hour the cost to perform monthly maintenance inspections is $2.7 million per year or $90 per tank per year.

 Based on comments received, the Department believes that the majority of unconventional well operators are already engaged in some form of periodic tank inspection. With the flexibility of being able to use operator generated forms, the Department does not believe that this provision represents a significant burden on unconventional operators.

 The Department believes that periodic inspections are appropriate common sense accident prevention steps that every storage tank operator should follow. In addition, it is almost always less costly to prevent an accident than to remediate the harm that is caused when an accident occurs. Remediation of a single spill could cost more the total annual cost to inspect all storage tanks utilized unconventional oil and gas well operators.

 The estimated new annual cost of this provision is $2.7 million.

Radiation protection action plan (§ 78a.58(d))

 The Department added § 78a.58(d) to this final-form rulemaking to require an operator processing fluids onsite to develop a radiation protection action plan which specifies procedures for monitoring and responding to radioactive material produced by the treatment process. This section also requires procedures for training, notification, recordkeeping and reporting to be implemented. This section does not require review or approval by the Department prior to implementation of the plan. In addition, the Department does not believe that a new or unique plan shall be developed for each individual well site where processing occurs. Many operators will probably find that a single plan developed under this provision is applicable to processing operations over large geographic areas.

 The Department estimates that processing which would require this plan occurs on approximately 75% of well sites or 326 sites per year.

 434 sites × 75% = 326 sites

 The Department also estimates that plans developed under this provision will be applicable to 50% of an operator's sites on average or 163 sites per year.

 326 sites × 50% = 163 sites

 Some operators may only need a single plan and others may need several, depending on their operations.

 The Department estimates that development of a radiation protection action plan under this section will cost between $2,000 and $5,000 per plan for initial development. In addition, to implement the plan, operators who develop a plan will need to purchase a dose rate meter. The Department estimates the cost of the dose rate meter to be $1,000—$2,000. Finally, operators will be required to provide training on the plan to staff. This training is typically conducted by the plan development consultant but may be conducted by others. The Department estimates that annual training of staff will cost $1,000—$2,000 per plan.

 Cost of development

 163 × $2,000 = $326,000

 163 × $5,000 = $815,000

 Cost of training

 163 × $1,000 = $163,000

 163 × $2,000 = $326,000

 A new meter will not be required for each plan. Operators may be able to use the same meter for multiple sites throughout the year depending on the location of the site. The Department estimate that industry will need to purchase 85 dose rate meters to comply with this requirement.

 Cost of meters

 85 × $1,000 = $85,000

 85 × $2,000 = $170,000

 The total annual cost is equal to the cost of development plus the cost of training. The total initial cost is equal to the cost of meters.

 $326,000 + $163,000 = $489,000

 $815,000 + $326,000 = $1,141,000

 Therefore, the estimated annual cost of this provision is between $489,000 and $1,141,000 and the estimated initial cost is estimated to be between $85,000 and $170,000.

Well development impoundment construction standards (§§ 78a.59a and 78a.59b)

 In this final-form rulemaking, §§ 78a.59a and 78a.59b impose construction and operation standards for well development impoundments including embankment construction standards, the need for surrounding well development impoundments with a fence and providing an impermeable plastic liner. The Department received comments from unconventional operators indicating that the cost of all new requirements applicable to well development impoundments, excluding fencing around the impoundment, is $250,000 to $500,000 per impoundment and a total cost of $25 million based on the Department's estimate of 100 existing freshwater impoundments. The commentator did not provide a breakdown of how the projected cost was derived.

 The Department disagrees with the commentator's cost estimate. First, many of the new requirements are only applicable to new impoundments. Operators shall only certify that existing impoundments meet the requirement for having a synthetic liner, being surrounded by a fence and properly storing MIW. This final-form rulemaking does not require any certification of structural integrity or a groundwater depth determination for existing impoundments so those costs should not be considered for existing impoundments. The requirement to ensure that MIW is properly stored exists regardless of the well development requirements in Chapter 78a so those costs should not be considered for existing impoundments.

 The Department understands that the majority of existing well development impoundments already have an impermeable synthetic liner. In addition, it is important to note that the well development impoundment requirements do not apply to water sources such as lakes or ponds, so to the extent that commentators included these types of facilities in their cost estimates, they may have overestimated. The Department estimates that 90% of the existing well development impoundments have a synthetic liner installed so only a small number of well development impoundments will require addition of a synthetic liner under this final-form rulemaking. The Department made the initial estimate of 100 existing well development impoundments in 2013 which would equate to an average of 20 well development impoundments constructed per year. Based on this rate of development, the number of existing well development impoundments is estimated to be 140 since 2 years have passed since the initial estimation.

 The Department estimates that on average, a well development impoundment will require 250,000 square feet of synthetic liner to comply with this final-form rulemaking. The estimated cost of installed 30 mil HDPE liner to meet this requirement is 40¢/square foot resulting in a total cost of $1.26 million.

 250,000 × 0.40 × 90% × 140 = $1,260,000 for liner installation

 The cost of the fencing is dependent upon the size of the impoundment and the type of fencing used. Based on 140 well development impoundments throughout this Commonwealth and assuming that none of them currently have fencing the Department estimates that the total cost of this provision is between $980,000 and $7 million.

 $7,000 × 140 = $980,000

 $50,000 × 140 = $7,000,000

 This final-form rulemaking also requires operators to register the location of well development impoundments with the Department. Assuming a total of 140 existing well development impoundments, the Department estimates a total cost of $13,000.

 $1,260,000 + $980,000 + $13,000 = $2,253,000

 $1,260,000 + $7,000,000 + $13,000 = $8,273,000

 The initial cost of this provision is estimated to be between $2.253 million and $8.273 million.

 For new impoundments, the total cost is dependent upon the number of new impoundments constructed. Based on past trends, the Department estimates that 20 new well development impoundments will be constructed each year. The standards under § 78a.59b provide reasonable requirements to ensure that well development impoundments are structurally sound and protective of public health and safety and the environment. The standard of structurally sound and protective of public health and safety and the environment is a standard that all well development impoundments should meet. To the extent that operators are currently engaged in the practice of constructing and operating impoundments that are not structurally sound and protective of public health and safety and the environment, the Department asserts that they are not only operating irresponsibly but also out of compliance with Department regulations. The Department also notes that § 78a.59a(b) allows an owner or operator to deviate from the requirements in this section provided that the alternate practices provides equivalent or superior protection to the requirements in § 78a.59a. Therefore, these sections should not create any significant new costs to responsible operators.

 The Department estimates the cost of determining the depth of the seasonal high groundwater table to be $3,500 per impoundment.

 The Department estimates a total cost of $100,000 for installing liners in each impoundment based on the cost of 40¢/square foot for installed 30 mil HDPE liner and 250,000 square feet of liner per impoundment on average.

 The Department estimates the cost of installing fencing to be $7,000—$50,000 per impoundment depending on the size of the impoundment and the type of fencing used.

 This results in a total estimated cost of $110,500 and $153,500 per impoundment and a total annual cost of $2.21 million to $3.07 million.

 ($3,500 + $100,000 + $7,000) × 20 = $2,210,000

 ($3,500 + $100,000 + $50,000) × 20 = $3,070,000

 Therefore, the total estimated annual cost of this provision is between $2.21 million and $3.07 million.

Centralized impoundments (§ 78a.59c)

 This final-form rulemaking requires unconventional operators to either close or obtain a permit from the Department's waste management program for existing centralized impoundments. The Department did not include a cost estimate for this provision in the proposed rulemaking because it allowed for continued use of these facilities under Chapters 78 and 78a. The cost of this provision is dependent on the number of facilities impacted and how operators decide to comply. The Department received significant comment on this section from unconventional operators. Commentators estimate that the cost to permit a new centralized impoundment under Chapter 289 may increase by $120,000 to $230,000 based on site conditions. Commentators also noted that if an operator chooses to close an existing permitted centralized impoundment due to this final-form rulemaking, an owner may realize a loss of $1.5 million to $2.5 million of investment plus the immediate additional costs to restore the site. If a centralized impoundment permit has been submitted to the Department under the current regulations and is pending review, an applicant would realize a loss of $150,000 to $250,000 plus costs associated with the time to prepare the application as a result of this revision.

 The Department does not agree with these cost estimates. First, the costs associated with restoration of existing centralized impoundments should not be considered because restoration of the centralized impoundment has always been required. Second, the standard for construction of a centralized impoundment under Chapter 78 and the Department's existing centralized impoundment program are substantially similar to those required by the residual waste regulations. The Department believes that the majority of costs associated with development of pending applications under the existing centralized impoundment program are applicable to the costs associated with the residual waste permit and therefore no cost should be associated with pending applications.

 The cost associated with this provision is dependent on the number of impoundments impacted. There are a total of 26 centralized impoundments operated by 6 unconventional operators in this Commonwealth. The Department believes that operators will choose to restore a number of the existing impoundments rather than obtain a permit from the Department's waste management program because older centralized impoundments were not constructed to standards as closely matched to the waste requirements as newer impoundments and those older impoundments also may be approaching the end of their useful lives. The Department presumes that the replacement cost for each centralized impoundment is between $1.5 million and $2.5 million. To the extent that operators choose to restore and replace all of the existing centralized impoundments, the estimated cost of this provision is between $33 million and $55 million.

 20 × $1,500,000 = $30,000,000

 20 × $2,500,000 = $50,000,000

 The initial cost of this provision is estimated to be between $39 million and $65 million.

 Based on past trends, the Department estimates that four centralized impoundments will be constructed per year. If the cost to permit and construct impoundments under Chapter 289 is $120,000 to $230,000 per impoundment, the estimated annual cost is between $480,000 and $920,000.

 Therefore, the total estimated annual cost of this provision is estimated to be between $480,000 and $920,000.

Onsite disposal (§§ 78a.62 and 78a.63)

 This final-form rulemaking requires unconventional operators to obtain a permit from the Department prior to disposing contaminated drill cuttings or drill cuttings from below the surface casing seat either in a pit or by land application on the well site. This revision removes the permit-by-rule structure for waste disposal on unconventional well sites. The Department does not expect this provision to add any significant cost for unconventional operations. It has become less and less common for unconventional operators to utilize onsite disposal of contaminated drill cuttings and drill cuttings from below the surface casing seat. In fact, there have been many instances where unconventional operators have exhumed previously encapsulated cuttings due to liability concerns. In addition, the practice of drilling many wells on a single site is generally incompatible with onsite disposal simply due to the volume of waste materials generated and the limited space available. An example of this is the Big Sky pad in Greene County where a total of 22 wells have been drilled as of May 2015.

 The total cost of this provision will be dependent on the number of well sites where operators seek permits for onsite disposal. The Department's review of waste disposal data for unconventional wells shows that for the reporting periods from January—June 2014, July—December 2014 and January—June 2015 cuttings from five wells have been disposed through onsite encapsulation and no cuttings have been disposed through land application. During that same time period, 1,746 unconventional wells were drilled so less than 0.3% of wells utilized onsite disposal. In addition, the five wells which utilized onsite disposal were vertical wells that generated 100—120 tons of cuttings so the total mass of cuttings disposed during that time was less than 600 tons while the total mass of drill cuttings generated during that time was over 2.1 million so less than 0.03% of the total mass of cuttings generated by unconventional wells was disposed through onsite disposal. Since these methods are so rarely used, the Department does not believe that this provision will impose any significant cost to the unconventional industry.

 The total new cost of this provision is $0.

Alternative waste management (§ 78a.63a)

 This section codifies the existing practice of requiring approval for alternative waste management practices. There is no cost associated with this section.

 The total new cost of this provision is $0.

Secondary containment (§ 78a.64a)

 This final-form rulemaking codifies the statutory requirement of the 2012 Oil and Gas Act for secondary containment.

 This cost estimate is conservative and assumes that an operator will use brand new secondary containment at every well site. According to industry secondary containment specialists, many of the secondary containment liners will be reused at multiple well sites. The Department reached out to secondary containment vendors upon finalization of the draft final-form regulations to ensure that cost estimates received in 2013 remained accurate. Vendors indicated that since the initial estimate there has been nearly a 50% decrease in the cost of materials typically used for containment as well as the cost for installation of secondary containment. The Department has retained the initial cost estimate to ensure to be conservative and because material costs fluctuate based on commodity markets.

 The Department estimates that the cost of providing secondary containment on an unconventional well site under § 78a.64a to be $140,000.

 $140,000 × 434 = $60,760,000

 The total annual cost of this provision is $60.76 million.

 Section 78a.64a requires materials used for secondary containment to have a coefficient of permeability not greater than 1 × 10^-10 cm/s. This requirement effectively eliminates use of natural materials such as clay soils for secondary containment on well sites. The Department does not believe that this standard adds any significant cost over a standard that may allow for the use of natural materials. First, natural materials that are sufficiently impermeable to be effective secondary containment are not generally readily available in this Commonwealth in the areas where unconventional well development occurs. This means that materials would have to be sourced from other areas and hauled to the well site. Clay soils shall also be installed in a much thicker layer than synthetic liners to provide sufficient protection which means more material shall be hauled to the site adding significant hauling costs over a synthetic material. Second, the cost of installation of natural materials as a secondary containment is also significantly more costly and time consuming than synthetic materials.

 When initially proposed, this provision required that the synthetic materials used for secondary containment must demonstrate compatibility with the contained fluid. Commentators pointed out that ASTM D5747 is a test for landfill liners and pits where the liner is submerged in diluted chemicals for extended period of time and the test costs around $5,000 to run on each chemical type found at a site. Operators suggest ASTM D543 as an alternate test. By considering the comments, this final-form rulemaking has been changed and the Department allows for the use of test methods if approved by the Department.

 Since this is an existing statutory requirement that unconventional operators must already comply with, the total new cost of this provision is $0.

 The total new cost of this provision is $0.

Site restoration (§ 78a.65)

 This section largely restates the restoration requirements in section 3216 of the 2012 Oil and Gas Act and incorporates the Department's interpretation of these requirements and the Chapter 102 requirements as outlined in the Policy for Erosion and Sediment Control and Stormwater Management for Earth Disturbance Associated with Oil and Gas Exploration, Production, Processing, or Treatment Operations or Transmission Facilities, Commonwealth of Pennsylvania, Department of Environmental Protection, No. 800-2100-008, which was finalized on December 29, 2012. The revisions to § 78a.65 in the ANFR were also intended to address comments on this section that indicated continuing confusion regarding what constitutes restoration as the term is used Chapters 78a and 102, and what the associated requirements are. The changes to this section in the ANFR clarify this question and in particular distinguish between areas not restored and other areas. ''Areas not restored'' do not fall within the provisions in § 102.8(n) and therefore must meet the requirements, among others, of § 102.8(g). Areas not restored include areas where there are permanent structures or impervious surfaces.

 The Department received significant comment on this provision from unconventional operators. Commentators argued that the Department failed to include any estimate for the cost associated with the new site restoration requirements. Commentators did not agree with the Department's position regarding cost savings due to the added provision of 2-year extension of the restoration period. Unconventional operators estimated that the cost of well site restoration will be approximately $200,000 to $300,000 per pad, not $50,000 as Department estimated. Therefore, rather than a $21.7 million savings, the restoration requirements are a cost of $130 million.

 The Department does not agree with these cost estimates. The restoration requirements in this section are not new and do not impose a new cost on the regulated community as previously explained. In addition, the Department disagrees with commentators' assertions that the extension requirement is merely a postponement of the cost. This section mirrors the requirements in section 3216(g) of the 2012 Oil and Gas Act that allow operators to request to extend the restoration period for up to 2 years so that an operator does not have to restore the site and then disturb it again if it plans to drill additional wells on the same well pad. The cost savings associated with the restoration extension are derived from avoiding the cost of restoring the site within 9 months of completion of drilling and later having to reconstruct the site and restore it again. The Department revised its estimate that this provision will result in $21.7 million in cost savings. Since the 2-year extension is provided by statute, operators may be granted an extension regardless of the status of § 78a.65, the revisions to this section do not represent a cost savings for operators.

 This section is intended to provide clarity for implementing existing requirements from the 2012 Oil and Gas Act and Chapter 102. To the extent that an operator would incur the costs previously listed, they would incur those costs regardless of the status of § 78a.65 because they are costs associated with complying with the 2012 Oil and Gas Act and Chapter 102.

 The total new cost of this provision is $0.

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