(a) General permit conditions.
  (1) Each condition applicable to a permit shall be incorporated into the permit either expressly or by reference. If incorporated by reference, a specific citation to the rules in this chapter shall be given in the permit. The requirements listed in this section are directly enforceable regardless of whether the requirement is a condition of the permit.
  (2) The permit may be modified, revoked and reissued, or terminated for cause. The filing of a request by the permittee for a permit modification, revocation and reissuance, or termination, or a notification of planned changes or anticipated noncompliance, does not stay any permit condition.
(b) General criteria. The director may issue a permit under this subchapter if the applicant demonstrates and the director finds that:
  (1) the injection and geologic storage of anthropogenic CO2 will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste as defined by Texas Natural Resources Code, §85.046(11);
  (2) with proper safeguards, both USDWs and surface water can be adequately protected from CO2 migration or displaced formation fluids;
  (3) the injection of anthropogenic CO2 will not endanger or injure human health and safety;
  (4) the construction, operation, maintenance, conversion, plugging, abandonment, or any other injection activity does not allow the movement of fluid containing any contaminant into USDWs, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR Part 142 or may otherwise adversely affect the health of persons;
  (5) the reservoir into which the anthropogenic CO2 is injected is suitable for or capable of being made suitable for protecting against the escape or migration of anthropogenic CO2 from the storage reservoir;
  (6) the geologic storage facility will be sited in an area with suitable geology, which at a minimum must include:
    (A) an injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the CO2 stream; and
    (B) a confining zone that is laterally continuous and free of known transecting transmissive faults or fractures over an area sufficient to contain the injected CO2 stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without compromising the confining zone or causing the movement of fluids that endangers USDWs;
  (7) the applicant for the permit meets all of the other statutory and regulatory requirements for the issuance of the permit;
  (8) the applicant has provided a letter from the Groundwater Advisory Unit of the Oil and Gas Division in accordance with §5.203(o) of this title (relating to Application Requirements);
  (9) the applicant has provided a letter of determination from TCEQ concluding that drilling and operating an anthropogenic CO2 injection well for geologic storage or constructing or operating a geologic storage facility will not impact or interfere with any previous or existing Class I injection well, including any associated waste plume, or any other injection well authorized or permitted by TCEQ;
  (10) the applicant has provided a signed statement that the applicant has a good faith claim to the necessary and sufficient property rights for construction and operation of the geologic storage facility for at least the first five years after initiation of injection in accordance with §5.203(d)(1)(A) of this title;
  (11) the applicant has paid the fees required in §5.205(a) of this title (relating to Fees, Financial Responsibility, and Financial Assurance);
  (12) the director has determined that the applicant has sufficiently demonstrated financial responsibility as required in §5.205(b) of this title; and
  (13) the applicant submitted to the director financial assurance in accordance with §5.205(c) of this title.
(c) Permit conditions for injection well construction.
  (1) Construction of anthropogenic CO 2 injection wells must meet the criteria in §5.203(e) of this title.
  (2) Within 30 days after the completion or conversion of an injection well subject to this subchapter, the operator must file with the division a complete record of the well on Commission Form W-2, Oil Well Potential Test, Completion or Recompletion Report and Log showing the current completion.
  (3) Except in the case of an emergency repair, the operator of a geologic storage facility must notify the director in writing at least 30 days prior to conducting any well workover that involves running tubing and setting packers, beginning any workover or remedial operation, or conducting any required pressure tests or surveys. Such activities shall not commence before the end of the 30 days unless authorized by the director. In the case of an emergency repair, the operator must notify the director of such emergency repair as soon as reasonably practical.
(d) Permit conditions for operating a geologic storage facility.
  (1) Operating plan.
    (A) The operator must maintain and comply with the approved operating plan.
    (B) Prior to approval for the operation of a Class VI injection well, the operator shall submit, and the director shall consider, the following information:
      (i) the final AOR based on modeling, using data obtained during logging and testing of the well and the formation as required by clauses (ii), (iii), (iv), (vi), (vii), and (x) of this subparagraph;
      (ii) any relevant updates, based on data obtained during logging and testing of the well and the formation as required by clauses (iii), (iv), (vi), (vii), and (x) of this subparagraph to the information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, submitted to satisfy the requirements of §5.203(c)(2) and (3) of this title;
      (iii) information on the compatibility of the CO2 stream with fluids in the injection zones and minerals in both the injection and the confining zones, based on the results of the formation testing program, and with the materials used to construct the well;
      (iv) the results of the formation testing program required by §5.203(f) of this title;
      (v) final injection well construction procedures that meet the requirements of §5.203(e) of this title;
      (vi) the status of corrective action on wells in the AOR;
      (vii) all available logging and testing program data on the well required by §5.203(f) of this title;
      (viii) a demonstration of mechanical integrity pursuant to §5.203(h) of this title;
      (ix) any updates to the proposed AOR and corrective action plan, testing and monitoring plan, injection well plugging plan, post-injection storage facility care and closure plan, or the emergency and remedial response plan submitted under §5.203(m) of this subchapter, which are necessary to address new information collected during logging and testing of the well and the formation as required by this section, and any updates to the alternative post-injection storage facility care timeframe demonstration submitted under §5.203(m) of this title, which are necessary to address new information collected during the logging and testing of the well and the formation as required by this section; and
      (x) any other information requested by the director.
  (2) Operating criteria.
    (A) Injection between the outermost casing protecting USDWs and the well bore is prohibited.
    (B) The total volume of CO2 injected into the storage facility must be metered through a master meter or a series of master meters. The volume and/or mass of CO2 injected into each injection well must be metered through an individual well meter. If mass is determined using volume, the operator must provide calculations.
    (C) The operator must comply with a maximum surface injection pressure limit approved by the director and specified in the permit. In approving a maximum surface injection pressure limit, the director must consider the results of well tests and, where appropriate, geomechanical or other studies that assess the risks of tensile failure and shear failure. The director must approve limits that, with a reasonable degree of certainty, will avoid initiation or propagation of fractures in the confining zone or cause otherwise non-transmissive faults or fractures transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection fluids or formation fluids in a manner that endangers USDWs. The Commission shall include in any permit it might issue a limit of 90 percent of the fracture pressure to ensure that the Cont'd...