(a) Purpose. The purpose of this section is to provide a procedure by which an operator can obtain Railroad Commission approval and certification of enhanced oil recovery (EOR) projects pursuant to Texas Tax Code, §202.052, §202.054, and §202.0545.     
      (b) Applicability.      
        (1) This section applies to:                  (A) new EOR projects and the change from secondary EOR projects to tertiary projects which qualify as new EOR projects, and which begin active operation on or after September 1, 1989; and                   (B) expansions of existing EOR projects.         
        (2) An EOR project may not qualify as an expansion if the project has qualified as a new EOR project under this section.       
      (c) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise.      
        (1) Active operation--The start and continuation of a fluid injection program for a secondary or tertiary recovery project to enhance the displacement process in the reservoir. Applying for permits and moving equipment into the field alone are not considered active operations.       
        (2) Anthropogenic carbon dioxide--Carbon dioxide produced as a result of human activities.       
        (3) Commission--The Railroad Commission of Texas.       
        (4) Commission representative--A commission employee authorized to act for the commission. Any authority given to a commission representative is also retained by the commission. Any action taken by the commission representative is subject to review by the commission.       
        (5) Comptroller--The Comptroller of Public Accounts.       
        (6) Enhanced oil recovery project (EOR)--The use of any process for the displacement of oil from the reservoir other than primary recovery and includes the use of an immiscible, miscible, chemical, thermal, or biological process. This term does not include pressure maintenance or water disposal projects.       
        (7) Existing enhanced recovery project--An EOR project that has begun active operation but was not approved by the Commission as a new EOR project.       
        (8) Expanded enhanced recovery project or expansion--The addition of injection and producing wells, the change of injection pattern, or other commission approved operating changes to an existing enhanced oil recovery project that will result in the recovery of oil that would not otherwise be recovered.       
        (9) Fluid injection--Injection through an injection well of a fluid (liquid or gaseous) into a producing formation as part of an EOR project.       
        (10) Incremental production--The volume of oil produced by an expanded enhanced recovery project in excess of the production decline rate established under conditions before expansion of an existing enhanced recovery project.       
        (11) Oil recovery from an enhanced recovery project--The oil produced from the designated area the commission certifies to be affected by the project.       
        (12) Operator--The person recognized by the commission as being responsible for the actual physical operation of an EOR project and the wells associated with the EOR project.       
        (13) Positive production response--Occurs when the rate of oil production from wells within the designated area affected by an EOR project is greater than the rate that would have occurred without the project.       
        (14) Pressure maintenance--The injection of fluid into the reservoir for the purpose of maintaining the reservoir pressure at or near the bubble point or other critical pressure wherein fluid injection volumes are not sufficient to refill existing reservoir voidage in the approved project area and displace oil that would not be displaced by primary recovery operations.       
        (15) Primary recovery--The displacement of oil from the reservoir into the wellbore(s) by means of the natural pressure of the oil reservoir, including artificial lift.       
        (16) Production decline rate--The projected future oil production from a project area as extrapolated by a method approved by the commission.       
        (17) Recovered oil tax rate--The tax rate provided by the Tax Code, §202.052(b).       
        (18) Secondary recovery project--An enhanced recovery project that is not a tertiary recovery project.       
        (19) Termination--Occurs when the approved fluid injection program associated with an EOR project stops or is discontinued.       
        (20) Tertiary recovery project--An EOR project using a tertiary recovery method (as defined in the federal June 1979 energy regulations referred to in the Internal Revenue Code of 1986, §4993, or approved by the United States secretary of the treasury for purposes of administering the Internal Revenue Code of 1986, §4993, without regard to whether that section remains in effect) including those listed as follows:                  (A) Alkaline (or caustic) flooding--An augmented waterflooding technique in which the water is made chemically basic as a result of the addition of alkali metals.                   (B) Carbon dioxide augmented waterflooding--Injection of carbonated water, or water and carbon dioxide, to increase waterflood efficiency.                   (C) Cyclic steam injection--The alternating injection of steam and production of oil with condensed steam from the same well or wells.                   (D) Immiscible carbon dioxide displacement--Injection of carbon dioxide into an oil reservoir to effect oil displacement under conditions in which miscibility with reservoir oil is not obtained.                   (E) In situ combustion--Combustion of oil in the reservoir, sustained by continuous air injection, to displace unburned oil toward producing wells.                   (F) Microemulsion, or micellar/emulsion, flooding--An augmented waterflooding technique in which a surfactant system is injected in order to enhance oil displacement toward producing wells. A surfactant system normally includes a surfactant, hydrocarbon, cosurfactant, an electrolyte and water, and polymers for mobility control.                   (G) Miscible fluid displacement--An oil displacement process in which gas or alcohol is injected into an oil reservoir, at pressure levels such that the injected gas or alcohol and reservoir oil are miscible. The process may include the concurrent, alternating, or subsequent injection of water. The injected gas may be natural gas, enriched natural gas, a liquefied petroleum gas slug driven by natural gas, carbon dioxide, nitrogen, or flue gas. Gas cycling, i.e., gas injection into gas condensate reservoirs, is not a miscible fluid displacement technique nor a tertiary enhanced recovery technique within the meaning of this section.                   (H) Polymer augmented waterflooding--Augmented waterflooding in which organic polymers are injected with the water to improve a real and vertical sweep efficiency.                   (I) Steam drive injection--The continuous injection of steam into one set of wells (injection wells) or other injection source to effect oil displacement toward and production from a second set of wells (production wells).         
        (21) Water disposal project--The injection of produced water into the reservoir for the purpose of disposing of the produced water wherein the water injection volumes are not sufficient to refill existing reservoir voidage in the approved project area and displace oil that would not be displaced by primary recovery operations.       
      (d) Application requirements. To qualify for the recovered oil tax rate the operator shall:      
        (1) submit an application for approval on the appropriate form. All applications must be filed at the Commission's Austin office. The form shall be executed and certified by a person having knowledge of the facts entered on the form. If an application is already on file under the Natural Resources Code, Chapter 101, Subchapter B, or for approval as a tertiary recovery project for purposes of the Internal Revenue Code of 1986, §4993, the operator may file a new EOR project and area designation application if the active operation of the project does not begin before the application under this section is approved by the Commission;       
        (2) submit all necessary forms to the Oil and Gas Division and provide the Commission with any relevant information required to administer this section such as: area plats showing the proposed project area and all injection and producing wells within the area, production and injection history, planned enhanced oil recovery procedures, and any other pertinent data;       
        (3) obtain a unitization agreement if required for purposes of carrying out the project under the Natural Resources Code, Chapter 101, Subchapter B. The Commission may not approve the project unless the unitization is approved; and       
        (4) submit an application on the appropriate form and obtain the necessary permits to conduct fluid injection operations pursuant to §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) (Statewide Rule 46), if such permits have not already been obtained.       
      (e) Concurrent applications. The operator may file concurrently:      
        (1) an application for approval of a new or expanded EOR project under this section, together with;       
        (2) an application for approval of a unitization agreement for purposes of carrying out the enhanced oil recovery project under the Natural Resources Code, §§101.001 et seq.; or       
        (3) an application for approval for certification of the project as a tertiary recovery project.       
      (f) Opportunity for hearing. A commission representative may administratively approve the application. If the commission representative denies administrative approval, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the commission.     
      (g) Approval and certification.      
        (1) Project approval. In order to be eligible for the recovered oil tax rate as provided in the Tax Code, §202.052(b), the operator shall apply for and be granted Commission approval of a new EOR project or an expansion of an existing EOR project, prior to commencing active operation of the new project or expanded project. For a project to be approved the operator shall:                  (A) prove that it qualifies as an EOR project;                   (B) designate the area to be affected by the project and obtain Commission approval of the designation; and                   (C) if production from the wells within the project area is reported with production from wells not in the project area, designate the method to account for and report production from the project area.         
        (2) Positive production response certificate.                  (A) The operator of an EOR project that meets the requirements of this section shall demonstrate to the Commission a positive oil production response before the operator can receive Commission certification of such a positive production response. The certification date may be any date desired by the operator, subject to Commission approval, following the date on which a positive oil production response first occurred. The operator shall apply for a positive production response certificate within three years of project approval for secondary projects, and within five years of project approval for tertiary projects, to qualify for the recovered oil tax rate. The oil produced from the designated area of a new EOR project or incremental oil produced from the designated area of an expanded EOR project after the date of certification of a positive production response is eligible for the recovered oil tax rate. The operator shall apply to the comptroller pursuant to the Tax Code, §202.052 and §202.054, to qualify for the recovered oil tax rate.                   (B) The application for positive response certification shall include:                      (i) production and injection graphs with supporting tabular data illustrating a positive production response and volumes of water or other substances that have been injected on the designated area since the initiation of the new or the expanded EOR project;                       (ii) a plat of the affected area showing all injection and producing wells, with completion dates; and                       (iii) any other data requested by the Oil and Gas Division.                     (C) The application for the positive production response certificate shall be processed administratively. If the Commission representative denies administrative approval, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the Commission.         
      (h) Annual reporting.      
        (1) The operator shall file an annual report on the appropriate form with the Oil and Gas Division each year the project remains eligible for the reduced severance tax rate. This form shall be filed within 30 days of the first anniversary of the date that the Commission acted on the EOR positive production response certification application and annually thereafter.       
        (2) The report shall contain the following:                  (A) Commission certification date of positive production response;                   (B) monthly volume of injected fluid(s) and anthropogenic carbon dioxide;                   (C) number of well(s) used for injection;                   (D) monthly production of oil, gas, and water;                   (E) number of active producing wells; and                  Cont'd...