SECTION 3.50. Enhanced Oil Recovery Projects--Approval and Certification for Tax Incentive

(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

(F) any other relevant information requested by the Oil and Gas Division.

(i) Reduced or enlarged areas. The operator may apply for reduced or enlarged project area certification if the application for reduction or enlargement is received prior to the filing of an application for positive production response certification of the original enhanced oil recovery project.

(j) Termination and penalty. Upon approval by the Commission and the comptroller, the recovered oil tax rate shall continue for a maximum of 10 years, unless the project is sooner terminated. If the project is terminated prior to the 10-year period, the operator shall notify the Commission and the comptroller in writing within 30 days after the last day of active operations. Failure to so notify may result in civil penalties, interest, and the tax due. If the Commission determines a project has been terminated or there is action that affects the tax rate, it shall notify the comptroller immediately in writing.

(k) Additional tax rate reduction for enhanced recovery projects using anthropogenic carbon dioxide.

(1) Subject to the limitations provided by Texas Tax Code, §202.0545, until the later of the seventh anniversary of the date that the Comptroller of Public Accounts first approves an application for a tax rate reduction under this subsection or the effective date of a final rule adopted by the United States Environmental Protection Agency regulating carbon dioxide as a pollutant, the producer of oil recovered through an EOR project that qualifies under Texas Tax Code, §202.054, for the recovered oil tax rate provided by Texas Tax Code, §202.052(b), is entitled to an additional 50 percent reduction in that tax rate if in the recovery of the oil the EOR project uses carbon dioxide that:

(A) is captured from an anthropogenic source in this state;

(B) would otherwise be released into the atmosphere as industrial emissions;

(C) is measurable at the source of capture; and

(D) is sequestered in one or more geological formations in this state following the EOR process.

(2) In the event that a portion of the carbon dioxide used in the EOR project is anthropogenic carbon dioxide that satisfies the criteria of paragraph (1) of this subsection and a portion of the carbon dioxide used in the project fails to satisfy the criteria of paragraph (1) of this subsection because it is not anthropogenic, the tax reduction provided by paragraph (1) of this subsection shall be reduced to reflect the proportion of the carbon dioxide used in the project that satisfies the criteria of paragraph (1) of this subsection.

(3) To qualify for the tax rate reduction under this subsection, the operator shall:

(A) apply for a certification from the Commission if carbon dioxide used in the project is to be sequestered in an oil or natural gas reservoir; and

(B) apply to the Comptroller of Public Accounts for the reduction and include with the application any information and documentation that the comptroller may require.

(4) To qualify for the additional reduced recovered oil tax rate under this subsection the operator shall:

(A) submit an application for certification to the Commission's Austin Office for approval on the appropriate form that is executed and certified as provided for on the form; and

(B) provide the Commission with:

(i) plats showing the proposed project area and all wells within the area;

(ii) production and injection history;

(iii) planned enhanced oil recovery procedures;

(iv) information to demonstrate that the carbon dioxide to be injected is anthropogenic and a description of the method(s) of capturing and measuring the captured carbon dioxide at the source;

(v) a description of the planned sequestration program reasonably expected to ensure that at least 99% of the sequestered carbon dioxide will remain sequestered for at least 1,000 years;

(vi) planned monitoring and verification measures, including the planned duration of such measures, that will be employed to demonstrate that the sequestration program is performing as expected; and

(vii) any other pertinent information requested by the Commission.

(5) The Commission may issue the certification for the reduced tax rate under this subsection only if the Commission finds that, based on substantial evidence, there is a reasonable expectation that:

(A) the operator's planned sequestration program will ensure that at least 99 percent of the anthropogenic carbon dioxide sequestered will remain sequestered for at least 1,000 years; and

(B) the operator's planned sequestration program includes appropriately designed monitoring and verification measures that will be employed for a period sufficient to demonstrate whether the sequestration program is performing as expected.

(6) The operator is responsible for making application to the Comptroller of Public Accounts for the additional tax rate reduction.

(7) The additional tax rate reduction under this subsection does not apply and the operator will be required to repay the amount of tax that would have been imposed in the absence of this subsection if the operator's sequestration program or the operator's monitoring and verification measures differ substantially from the planned program approved by the Commission.

(8) In conjunction with the Annual Report required to be filed under subsection (h) of this section, an operator shall submit information concerning the operator's monitoring and verification measures results as proposed in the application for certification to demonstrate whether the sequestration program is performing as expected. In the event that the operator's sequestration program, including monitoring and verification measures, differs substantially from the program certified by the Commission under subsection (k)(5) of this section, the operator shall include with the Annual Report a written description of any material changes in the sequestration program.

(9) A Commission representative may administratively approve or deny an application for certification. If the Commission representative administratively denies an application, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the Commission.

Source Note: The provisions of this §3.50 adopted to be effective February 20, 1990, 15 TexReg 652; amended to be effective March 18, 1992, 17 TexReg 1615; amended to be effective November 17, 1993, 18 TexReg 7922; amended to be effective April 6, 1998, 23 TexReg 3435; amended to be effective October 12, 2003, 28 TexReg 8585; amended to be effective January 7, 2008, 33 TexReg 114