Current through Reg. 49, No. 12; March 22, 2024
(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, §
RSA 202.052, §
RSA
202.054, and §
RSA
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, §
RSA
202.052<subdiv>(b)</subdiv>.
(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 §
RSA
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, §§
RSA
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, §
RSA
202.052<subdiv>(b)</subdiv>, 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, §
RSA 202.052 and
§
RSA
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, §
RSA
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, §
RSA
202.054, for the recovered oil tax rate
provided by Texas Tax Code, §
RSA
202.052<subdiv>(b)</subdiv>, 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.