Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 1.
PRACTICE AND PROCEDURE
Subchapter I. PERMIT PROCESSING
16 TAC §1.201
The Railroad Commission of Texas adopts amendments to §1.201,
relating to Time Periods for Processing Applications and Issuing Permits Administratively,
without changes to the proposal published in the November 9, 2001, issue of
the
Texas Register
(26 TexReg 8937). The Commission
adopts the amendments in order to conform Table 1 in §1.201 with substantive
changes in §§3.14 and 3.78, which the Commission is adopting in
a separate rulemaking, Docket No. 20-0228899, as a result of changes made
to the Texas Natural Resources Code by Senate Bill (SB) 310, 77th Legislature
(2001), and with other changes to Commission fees required by SB 310.
Texas Natural Resources Code, §81.0521, as amended by SB 310, authorizes
the Commission to collect a fee of $150 with each exception to any Commission
rule. Texas Natural Resources Code, §85.2021, as amended by SB 310, authorizes
the Commission to collect a fee of $200 for each application under §3.38,
relating to Well Densities. Texas Natural Resources Code, §91.1013, as
amended by SB 310, authorizes the Commission to collect a fee of $200 with
each application for a fluid injection well permit and a fee of $300 for each
application to discharge to surface water. The Commission amends Table 1 in §1.201
only to identify the new amount of the filing fee required for the specific
applications subject to the provisions of §1.201.
In Table 1 of §1.201, application fees for permits under Commission
rule §3.8 to discharge hydrostatic test water; produced water to inland
waters; produced water to the Gulf of Mexico from a non-land based facility;
and gas plant effluent will increase from the current $200 to $300. The application
fee for an exception under §3.9 for a disposal well permit (Form W- 14)
will increase from the current $50 to $150. The application fee for a density
exception under §3.38 will increase from the current $50 to $200. Application
fees for injection permits under §3.46 (Forms H-1, H-1A, H-7, and H-1S)
will change from the current $100 to $200; fees for other exceptions will
increase from the current $50 to $150.
The Commission also amends subsection (c)(5) to clarify the wording. As
originally worded, there could be an overlap of the initial review period
and the final review period. The Commission intends that the final review
period not begin until the conclusion of the initial review period; the amendment
makes that clarifying correction.
The Commission received no comments on the proposed amendments.
The Commission adopts the amendments to §1.201 pursuant
to Texas Government Code, §§2005.001-2005.007, which require the
Commission to adopt procedural rules for processing permit applications and
issuing permits and to establish by rule a complaint procedure allowing permit
applicants to complaint directly to the chief administrator of the agency;
Texas Government Code, §2001.004, which requires agencies to adopt rules
of practice stating the nature and requirements of all available formal and
informal procedures; Texas Natural Resources Code, §§81.051 and
81.052, which provide the Commission with jurisdiction over all persons owning
or engaged in drilling or operating oil or gas wells in Texas and the authority
to adopt all necessary rules for governing and regulating persons and their
operations under the jurisdiction of the Commission; and Texas Natural Resources
Code, §§81.0521 and 91.1013, as amended by SB 310.
Texas Government Code, §§2001.004 and 2005.001-2005.007, and
Texas Natural Resources Code, §§81.051, 81.052, 81.0521, 91.1013,
as amended by SB 310, are affected by the rules as amended.
Issued in Austin, Texas, on December 20, 2001.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on December 20, 2001.
TRD-200108166
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: November 9, 2001
For further information, please call: (512) 463-7008
16 TAC §3.14, §3.78
The Railroad Commission of Texas (Commission) adopts amendments
to §3.14, relating to Plugging, and §3.78, relating to Fees, Performance
Bonds and Alternate Forms of Financial Security Required to be Filed with
changes to the versions published in the November 9, 2001, issue of the
The Commission adopts the amendments as a result of changes to the Texas
Natural Resources Code made by Senate Bill 310, 77th Legislature (2001), which
became effective September 1, 2001.
The Commission adopts the amendments to §3.78(b)(4) under the provisions
of Texas Natural Resources Code, §81.0521, as amended by Senate Bill
310, which authorizes the Commission to collect a fee of $150 with each exception
to any Commission rule. The amendments to §3.78(b)(4) reflect the statutory
authorization to collect the $150 fee.
The Commission adopts the amendments to §3.78(b)(5) under the provisions
of Texas Natural Resources Code, §85.2021, as amended by Senate Bill
310, which now authorizes the Commission to collect a fee of $200 with each
exception to §3.37, relating to Statewide Spacing Rule (Statewide Rule
37) and §3.38, relating to Well Densities (Statewide Rule 38). The amendments
to §3.78(b)(5) reflect the statutory authorization to collect the $200
fee.
The Commission adopts the amendments to §3.78(b)(12) under the provisions
of Texas Natural Resources Code, §81.0522, which authorizes the Commission
to collect a fee of up to $150 with each application for a well category determination
under the Natural Gas Policy Act (15 U.S.C. §§3301-3432). The amendments
to §3.78(b)(12) reflect the statutory authorization to collect the $150
fee.
The Commission adopts the amendments to §3.78(b)(1), (3), and (6)
under the provisions of Texas Natural Resources Code, §85.2021, which
authorizes the Commission to collect a fee with each application or materially
amended application for a permit to drill, deepen, plug back, or reenter a
well of: (1) $200 if the total depth of the well is 2,000 feet or less; (2)
$225 if the total depth of the well is greater than 2,000 feet but less than
or equal to 4,000 feet; (3) $250 if the total depth of the well is greater
than 4,000 feet but less than or equal to 9,000 feet; or (4) $300 if the total
depth of the well is greater than 9,000 feet. Additionally, amended Texas
Natural Resources Code, §85.2021, authorizes the Commission to collect
a fee of $150 when an applicant requests the Commission expedite an application
for a permit to drill, deepen, plug back, or reenter a well, and a fee of
$300 for each application for an extension of time to plug a well pursuant
to Commission rules. The amendments to §3.78(b)(1), (3), and (6) reflect
the statutory authorization to collect the increased fees.
The Commission adopts the amendments to §3.78(b)(8) and (9) under
the provisions of Texas Natural Resources Code, §91.1013, which now authorizes
the Commission to collect a fee of $200 with each application for a fluid
injection well permit and authorizes the Commission to collect a fee of $300
for each application to discharge to surface water. The amendments to §3.78(b)(8)
and (9) reflect the statutory authorization to collect the increased fees.
The Commission adopts the amendments to §3.78 under the provisions
of Texas Natural Resources Code, §91.104, which now requires operators
to file financial security or alternate forms of financial security. The amended
provisions of Texas Natural Resources Code, §91.104: (1) allow operators
to submit a cash deposit to the Commission in the same amount that would be
required for a bond or letter of credit; (2) add a new determination on the
availability of bonds at reasonable prices before an operator with an acceptable
record of compliance can choose to file a $1,000 annual fee in lieu of posting
other acceptable forms of financial security; (3) increase the annual fee
for operators with an acceptable record from $100 to $1,000; (4) eliminate
the option of an operator meeting its financial security requirement by providing
the Commission with a first lien on equipment; and (5) increase the nonrefundable
cash alternative fee from 3% of the amount that would be required for a bond
or letter of credit to 12.5%.
Commission records show that in the approximately six-month period between
January 18, 2001, and June 26, 2001, an additional 117 operators have filed
organizational bonds. This increase appears to be directly correlated to the
Commission's previous amendment of §§3.14 and 3.78 to adopt financial
security requirements for inactive wells effective November 1, 2000. The increase
in operators filing organizational bonds also reflects a general availability
of bonds for operators. Based on this increase in the number of operators
filing organizational bonds, the Commission has determined that bonds are
available at reasonable prices. This determination is included in proposed §3.78(f)(1)
to satisfy the statutory requirement that the Commission make such a determination.
The Commission further recognizes that while this determination is generally
applicable to operators throughout the state, there may be specific operators
who are unable to obtain bonds at a reasonable price. Accordingly, the Commission
has included as proposed §3.78(f)(2) the opportunity for an operator
to request a hearing to determine that it cannot obtain a bond at a reasonable
price. Proposed §3.78(f)(2) also sets forth the minimum required evidentiary
burden of proof to be submitted by the operator to support a determination
that bonds are not obtainable at reasonable prices. The Commission has determined
that the minimum evidentiary showing should include: (1) evidence that no
fewer than three companies which have issued a bond filed with the Commission
in the past 12 months will not issue a bond to the requesting operator for
an annual fee less than 12% of the face amount of the bond; and (2) evidence
that the operator is otherwise eligible to file the $1,000 nonrefundable annual
fee.
The amendments to §3.78(l) also establish conditions for cash deposits.
The Commission will place any cash deposits in a special account within the
Oil Field Clean Up Fund Account. Any interest accruing on cash deposits will
be deposited into the Oil Field Clean Up Fund pursuant to Texas Natural Resources
Code, §91.111(c)(8). Cash deposits will not be refunded until an operator
ceases all Commission-regulated activity or another form of financial security
is accepted by the Commission.
The Commission also adopts the amendments to §3.14(b)(2) and (3) and §3.78(n)
under the provisions of Texas Natural Resources Code, §91.107, as amended
by Senate Bill 310, which requires operators acquiring an active or inactive
well to file either an individual performance bond or a blanket performance
bond with the Commission before operatorship of the well is transferred. The
statutory amendments require changes to Commission rules which did not specify
the type of financial security required to transfer a well. Prior Commission
rules did not require the operator obtaining wells through a transfer to file
a specific type of financial security. The amendments to §3.14(b)(2)
and (3) and §3.78(n) simply incorporate the statutory amendments.
The Commission also adopts amendments to §3.78(c) under the provisions
of Texas Natural Resources Code, §91.142, which requires operators filing
an organization report with the Commission to submit a fee not to exceed $1,000
to be calculated as follows: (1) for an operator of not more than 25 wells,
$300; (2) for an operator of more than 25 but not more than 100 wells, $500;
(3) for an operator of more than 100 wells, $1,000; (4) for an operator of
one or more natural gas pipelines, $100; (5) for an operator of one or more
service activities or facilities, including liquids pipelines, who does not
operate any wells, an amount to be determined by the Commission, but not less
than $300 or more than $500; (6) for an operator of one or more service activities
or facilities, including liquids pipelines, who also operates one or more
wells, an amount to be determined by the Commission, but not less than $300
or more than $1,000; and (7) for an entity not currently performing operations
under the jurisdiction of the Commission, $300. The amendments reflect the
statutory authorization to collect an annual organization report fee based
on the number of wells, service activities or facilities operated by the operator.
The required filing fee for operators who operate one or more service activities
but no wells was set at $300 for pollution cleanup contractors, directional
surveyors, approved cementers for plugging wells, and operators physically
moving or storing crude or condensate. All other operators of other service
activities or facilities, including liquids pipelines, are required to submit
a fee of $500. The required filing fee for operators who operate both wells
and one or more service activities or pipelines is based on the sum of any
fee associated with the number of wells operated plus the separate fee charged
for each category of service activity, facility or pipeline.
The Commission also adopts an amendment to §3.78(b)(15) requiring
operators who submit a check that is not honored on presentment to submit
any subsequent payments in the form of a credit card, cashier's check, or
cash for a period of 24 months. The amendment will promote administrative
efficiency by reducing the number of dishonored checks submitted to the Commission.
The Commission also notes that under the provisions of Texas Natural Resources
Code, §91.1041 and §91.1042, as amended by Senate Bill 310, the
Commission is required to adopt rules setting a reasonable amount of financial
security for each bay or offshore well above the base amount of financial
security required to be submitted by each operator. The amount of financial
security for each bay or offshore well above the base amount will be the subject
of a separate rulemaking. The Commission has included in the amendments to §3.78
definitions of bay, offshore and land wells in anticipation of the future
amendments.
The amendments to §§3.14 and 3.78 implement statutory changes
made to financially strengthen and to better use the state's Oil Field Clean
Up Fund ("OFCUF"). The statutory changes were recommended during the agency
review process of the Commission by the Sunset Advisory Commission.
The financial strength of the OFCUF is increased by statutory changes and
corresponding rule amendments raising the required amount for filing fees
and by adding an annual organization report filing fee. Broadened financial
security requirements will ensure that sufficient financial security is in
place to adequately fund clean up and plugging operations. The expanded financial
security requirements will allow the Commission to more effectively use a
fiscally stronger OFCUF.
In addition to the substantive changes previously discussed, the Commission
reorganizes and clarifies §3.78. The new format groups together in §3.78
both the existing and the amended provisions relating to fees charged by the
Commission. Additionally, the new format of §3.78 incorporates the references
in §3.14 to individual well bonds and letters of credit, and groups these
references with the existing and the amended provisions related to financial
security requirements in 3.78. Finally, §3.78(p) is clarified by noting
that the requirements date from the original enactment of the subsection.
The substantive changes in filing fees and financial security requirements
are made in §3.78. The amendments to §3.14(a)(1)(F) and (M) and §3.14(b)(2)
and (3) are adopted to conform with the substantive changes in §3.78.
Other changes in §3.14(a)(1) are made to conform the definitions in this
rule to Texas Register format requirements.
The Commission received three comments on the proposed amendments, two
from associations. The comments from the associations addressed only one amendment,
proposed §3.78(f)(2)(A). One comment was in favor of the amendment, and
one comment suggested additional changes. The first comment was received from
the Texas Independent Producers & Royalty Owners Association (TIPRO) to
proposed §3.78(f)(2)(A) which discusses the requirements at a hearing
requested by an operator to qualify to pay a $1,000.00 fee in lieu of filing
another form of financial security. TIPRO suggests that the Commission should
not state that an annual rate of 12% of the face amount of the bond is reasonable.
The Commission disagrees with this interpretation in light of Texas Natural
Resources Code §91.104(b)(5) which sets the amount for a cash alternative
payment in lieu of providing financial security at 12.5% of the face amount
of any financial security requirement. The 12% amount specified in proposed §3.78(f)(2)(A)
is based on the 12.5% amount for a cash alternative payment set by statute.
The amount adopted by the Legislature is presumed to be a reasonable amount
for the cash alternative payment. Because the 12% requirement in §3.78(f)(2)(A)
is based on this enactment, the same presumption of reasonableness should
therefore apply to the amount set in the proposed rule.
An additional comment was received from the Texas Land & Minerals Owners
Association (TLMA) supporting the determination that 12% of the face amount
of the bond annual rate is reasonable in §3.78(f)(2)(A). TLMA believes
that setting a cap will protect industry from excessive rates. TLMA also asserts
that if underwriters for bonds unreasonably charge a rate of 12%, that operators
will opt less expensive means of financial security, such as a letter of credit.
Market forces will then force bond underwriters to respond with lower rates.
The remaining comment was submitted by Statewide Bonding Agency and suggests
eight changes to the bond form currently used by the Commission. Statewide
Bonding Agency believes that the proposed changes will allow bonds to be issued
without additional restrictions which are not applied to letters of credit.
Statewide Bonding Agency believes that this will encourage more bond companies
to undertake surety obligations for operators. While many of the comments
appear to bear further investigation, the content of the Commission's bond
forms is not a subject of the present rulemaking.
Statewide Bonding Agency also suggests that the $1,000.00 fee in lieu of
filing another form of financial security discourages bonding companies from
providing bonds and therefore should be eliminated. The Commission notes that
the $1,000.00 fee in lieu of filing another form of financial security is
set by statute in Texas Natural Resources Code §91.104(b)(4). Additionally,
this option will be eliminated by additional amendments to Texas Natural Resources
Code §91.104(b)(4) which were passed by the Legislature to become effective
on September 1, 2004.
The Commission adopts the amendments to §§3.14 and
3.78 pursuant to Texas Natural Resources Code, §§81.051 and 81.052,
which provide the Commission with jurisdiction over all persons owning or
engaged in drilling or operating oil or gas wells in Texas and the authority
to adopt all necessary rules for governing and regulating persons and their
operations under the jurisdiction of the Commission, and under the provisions
of Senate Bill 310, 77th Legislature (2001).
The Texas Natural Resources Code, §§81.051, 81.052, 81.0521,
81.0522, 85.202, 85.2021, 88.011, 91.101, 91.1013, 91.103, 91.104, 91.1041,
91.1042, 91.105-91.108, 91.1091, 91.111- 91.113, 91.142, and the provisions
of Senate Bill 310, 77th Legislature (2001) are affected by the adopted amendments.
Issued in Austin, Texas on December 20, 2001.
§3.14.Plugging.
(a)
Definitions and application to plug.
(1)
The following words and terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise:
(A)
Active operation--Regular and continuing activities related
to the production of oil and gas for which the operator has all necessary
permits. In the case of a well that has been inactive for 12 consecutive months
or longer and that is not permitted as a disposal or injection well, the well
remains inactive for purposes of this section, regardless of any minimal activity,
until the well has reported production of at least 10 barrels of oil for oil
wells or 100 mcf of gas for gas wells each month for at least three consecutive
months.
(B)
Bay well--Any well under the jurisdiction of the Commission
for which the surface location is either:
(i)
located in or on a lake, river, stream, canal, estuary,
bayou or other inland navigable waters of the state; or,
(ii)
located on state lands seaward of the mean high tide line
of the Gulf of Mexico in water of a depth at mean high tide of not more than
100 feet that is sheltered from the direct action of the open seas of the
Gulf of Mexico.
(C)
Delinquent inactive well--An unplugged well that has had
no reported production, disposal, injection, or other permitted activity for
a period of greater than 12 months and for which, after notice and opportunity
for hearing, the Commission has not extended the plugging deadline.
(D)
Funnel viscosity--Viscosity as measured by the Marsh funnel,
based on the number of seconds required for 1,000 cubic centimeters of fluid
to flow through the funnel.
(E)
Good faith claim--A factually supported claim based on
a recognized legal theory to a continuing possessory right in a mineral estate,
such as evidence of a currently valid oil and gas lease or a recorded deed
conveying a fee interest in the mineral estate.
(F)
Individual well bond--A bond or letter of credit issued:
(i)
on a Commission-approved form;
(ii)
by a third party surety, insurance company, or financial
institution approved by the Commission; and
(iii)
to secure the timely and proper plugging of a specified
well and remediation of the wellsite in accordance with Commission rules.
(G)
Land well--Any well subject to Commission jurisdiction
for which the surface location is not in or on inland or coastal waters.
(H)
Offshore well--Any well subject to Commission jurisdiction
for which the surface location is on state lands in or on the Gulf of Mexico,
that is not a bay well.
(I)
Operator designation form--A certificate of transportation
authority and compliance or an application to drill, deepen, recomplete, plug
back, or reenter which has been completed, signed and filed with the Commission.
(J)
Productive horizon--Any stratum known to contain oil, gas,
or geothermal resources in producible quantities in the vicinity of an unplugged
well.
(K)
Reported production--Production of oil or gas, excluding
production attributable to well tests, accurately reported to the Commission
on a monthly producer's report.
(L)
To serve surface notice--To hand deliver a written notice
identifying the well to be plugged and the projected date the well will be
plugged to the intended recipient at least three days prior to the day of
plugging or to mail the notice by first class mail, postage pre-paid, to the
last known address of the intended recipient at least seven days prior to
the day of plugging.
(M)
Unbonded operator--An operator that has a current and active
organization report on file with the Commission but that does not have a current
individual performance bond, blanket performance bond, letter of credit, or
cash deposit as its financial security under §3.78 of this title (relating
to Fees, Performance Bonds, and Alternate Forms of Financial Security Required
to be Filed (Statewide Rule 78).
(N)
Usable quality water strata--All strata determined by the
Texas Natural Resource Conservation Commission to contain usable quality water.
(O)
Written notice--Notice actually received by the intended
recipient in tangible or retrievable form, including notice set out on paper
and hand-delivered, facsimile transmissions, and electronic mail transmissions.
(2)
The operator shall give the Commission notice of its intention
to plug any well or wells drilled for oil, gas, or geothermal resources or
for any other purpose over which the Commission has jurisdiction, except those
specifically addressed in §3.100(f)(1) of this title (relating to Seismic
Holes and Core Holes) (Statewide Rule 100), prior to plugging. The operator
shall deliver or transmit the written notice to the district office on the
appropriate form.
(3)
The operator shall cause the notice of its intention to
plug to be delivered to the district office at least five days prior to the
beginning of plugging operations. The notice shall set out the proposed plugging
procedure as well as the complete casing record. The operator shall not commence
the work of plugging the well or wells until the proposed procedure has been
approved by the district office. The operator shall not initiate approved
plugging operations before the date set out in the notification for the beginning
of plugging operations unless authorized by the district director. The operator
shall notify the district office at least four hours before commencing plugging
operations and proceed with the work as approved. The district director may
grant exceptions to the requirements of this paragraph concerning the timing
of notices when a workover or drilling rig is already at work on location,
ready to commence plugging operations. Operations shall not be suspended prior
to plugging the well unless the hole is cased and casing is cemented in place
in compliance with Commission rules.
(4)
The landowner and the operator may file an application
to condition an abandoned well located on the landowner's tract for usable
quality water production operations, provided the landowner assumes responsibility
for plugging the well and obligates himself, his heirs, successors, and assignees
as a condition to the Commission's approval of such application to complete
the plugging operations. The application shall be made on the form prescribed
by the Commission. In all cases, the operator responsible for plugging the
well shall place all cement plugs required by this rule up to the base of
the usable quality water strata.
(5)
The operator of a well shall serve surface notice on the
surface owner of the well site tract, or the resident if the owner is absent,
before the scheduled date for beginning the plugging operations. A representative
of the surface owner may be present to witness the plugging of the well. Plugging
shall not be delayed because of the lack of actual notice to the surface owner
or resident if the operator has served surface notice as required by this
paragraph. The district director may grant exceptions to the requirements
of this paragraph concerning the timing of notices when a workover or drilling
rig is already at work on location ready to commence plugging operations.
(b)
Commencement of plugging operations and extensions.
(1)
The operator shall complete and file in the district office
a duly verified plugging record, in duplicate, on the appropriate form within
30 days after plugging operations are completed. A cementing report made by
the party cementing the well shall be attached to, or made a part of, the
plugging report. If the well the operator is plugging is a dry hole, an electric
log status report shall be filed with the plugging record.
(2)
Plugging operations on each dry or inactive well shall
be commenced within a period of one year after drilling or operations cease
and shall proceed with due diligence until completed. Plugging operations
on delinquent inactive wells shall be commenced immediately unless the well
is restored to active operation. For good cause, a reasonable extension of
time in which to start the plugging operations may be granted pursuant to
the following procedures.
(A)
Wells that have been inactive for less than 36 months.
(i)
The Commission or its delegate may administratively grant
an extension of up to one year of the deadline for plugging a well that is
operated by an unbonded operator and has been inactive, without a return to
active operation, for a period of less than 36 months if the following criteria
are met:
(I)
The well and associated facilities are in compliance with
all other laws and Commission rules;
(II)
The operator's organization report is current and active;
(III)
The operator has, and upon request provides evidence
of, a good faith claim to a continuing right to operate the well;
(IV)
The operator has paid the proper fee as provided in §3.78
of this title (relating to Fees, Performance Bonds, and Alternative Forms
of Financial Security Required To Be Filed) (Statewide Rule 78);
(V)
The operator has tested the well in accordance with the
provisions of subparagraph (E) of this section and files with its application
proof of either:
(-a-)
a fluid level test conducted within 90 days prior to
the application for a plugging extension demonstrating that any fluid in the
wellbore is at least 250 feet below the base of the deepest usable quality
water strata; or,
(-b-)
a hydraulic pressure test conducted during the period
the well has been inactive demonstrating the mechanical integrity of the well;
and,
(VI)
The requested plugging extension will not extend beyond
the thirty-sixth month of inactivity.
(ii)
A plugging extension granted under this subparagraph may
not extend the period of inactivity beyond 36 months.
(B)
Wells that have been inactive for 36 months or longer.
(i)
The Commission or its delegate may administratively grant
an extension of up to one year of the deadline for plugging a well that is
operated by an unbonded operator and has been inactive, without a return to
active operation, for a period of 36 months or longer if the criteria set
out in subclauses (I)-(IV) of subsection (b)(2)(A)(i) of this section are
met, and, in addition:
(I)
The operator has tested the well in accordance with the
provisions of subparagraph (E) of this paragraph and files with its application
proof of either:
(-a-)
a fluid level test conducted within 90 days prior to
the application for a plugging extension demonstrating that any fluid in the
wellbore is at least 250 feet below the base of the deepest usable quality
water strata, or,
(-b-)
a hydraulic pressure test conducted during the period
the well has been inactive and not more than four years prior to the date
of application demonstrating the mechanical integrity of the well; and,
(II)
The operator files an individual well bond in the amount
provided for in §3.78(m) of this title (relating to Fees, Performance
Bonds, and Alternative Forms of Financial Security Required To Be Filed) (Statewide
Rule 78).
(ii)
An operator may rebut the presumed estimated plugging
costs for a specific well for which a plugging extension is sought at hearing
by clear and convincing evidence establishing a higher or lower prospective
plugging cost for the well. The operator, Commission staff, or any owner of
the surface or mineral estate on which the well is located may initiate a
hearing on the prospective plugging cost for a well for the purpose of setting
the amount of an individual well bond by filing a request for hearing.
(C)
Plugging of inactive wells operated by bonded operators.
An operator that maintains valid, Commission-approved financial security in
the form of an individual performance bond, blanket performance bond, letter
of credit, or cash deposit as provided in §3.78 of this title (relating
to Fees, Performance Bonds, and Alternate Forms of Financial Security Required
to be Filed) (Statewide Rule 78) will be granted a one-year plugging extension
for each well it operates that has been inactive for 12 months or more at
the time its annual organizational report is approved by the Commission if
the following criteria are met:
(i)
The well and associated facilities are in compliance with
all laws and Commission rules; and,
(ii)
The operator has, and upon request provides evidence of,
a good faith claim to a continuing right to operate the well.
(D)
Revocation or denial of plugging extension.
(i)
The Commission or its delegate may revoke a plugging extension
if the operator of the well that is the subject of the extension fails to
maintain the well and all associated facilities in compliance with Commission
rules; fails to maintain a current and accurate organizational report on file
with the Commission; fails to provide the Commission, upon request, with evidence
of a continuing good faith claim to operate the well; or fails to obtain or
maintain a valid individual well bond or organizational bond or letter of
credit as required by this subsection.
(ii)
If the Commission or its delegate declines to grant or
continue a plugging extension or revokes a previously granted extension, the
operator shall either return the well to active operation or, within 30 days,
plug the well or request a hearing on the matter.
(E)
The operator of any well more than 25 years old that becomes
inactive and subject to the provisions of this paragraph and the operator
of any well for which a plugging extension is sought under the terms of subparagraph
(A) or (B) of this paragraph shall plug or test such well to determine whether
the well poses a potential threat of harm to natural resources, including
surface and subsurface water, oil and gas.
(i)
In general, a fluid level test is a sufficient test for
purposes of this subparagraph. The operator must give the district office
written notice specifying the date and approximate time it intends to conduct
the fluid level test at least 48 hours prior to conducting the test; however,
upon a showing of undue hardship, the district office may grant a written
waiver or reduction of the notice requirement for a specific well test. The
Commission or its delegate may require alternate methods of testing if the
Commission deems it necessary to ensure the well does not pose a potential
threat of harm to natural resources. Alternate methods of testing may be approved
by the Commission or its delegate by written application and upon a showing
that such a test will provide information sufficient to determine that the
well does not pose a threat to natural resources.
(ii)
No test other than a fluid level test shall be acceptable
without prior approval from the district office. The district office shall
be notified at least 48 hours before any test other than a fluid level test
is conducted. Mechanical integrity test results shall be filed with the district
office and fluid level test results shall be filed with the Commission in
Austin. Test results shall be filed on a Commission-approved form, within
30 days of the completion of the test. Upon request, the operator shall file
the actual test data for any mechanical integrity or fluid level test that
it has conducted.
(iii)
Notwithstanding the provisions of clause (ii) of this
subparagraph, a hydraulic pressure test may be conducted without prior approval
from the district office, provided that the operator gives the district office
written notice specifying the date and approximate time for the test at least
48 hours prior to the time the test will be conducted, the production casing
is tested to a depth of at least 250 feet below the base of usable quality
water strata, or 100 feet below the top of cement behind the production casing,
whichever is deeper, and the minimum test pressure is greater than or equal
to 250 psig for a period of at least 30 minutes.
(iv)
If the operator performs a hydraulic pressure test in
accordance with the provisions of clause (iii) of this subparagraph, the well
shall be exempt from further testing for five years from the date of the test,
except to the extent compliance with paragraph (2) of subsection (b) of this
section requires more frequent testing. Further, the Commission or its delegate
may require the operator to perform testing more frequently to ensure that
the well does not pose a threat of harm to natural resources. The Commission
or its delegate may approve less frequent well tests under this subparagraph
upon written request and for good cause shown provided that less frequent
testing will not increase the threat of harm to natural resources.
(v)
Wells that are returned to continuous production, as evidenced
by three consecutive months of reported production of at least 10 barrels
of oil or 100 mcf of gas per month, need not be tested.
(3)
Transfer of operatorship. A transfer of operatorship submitted
for any well or lease will not be approved unless the operator acquiring the
well or lease has on file with the Commission financial security as provided
in §3.78 of this title (relating to Fees, Performance Bonds, and Alternate
Forms of Financial Security Required to be Filed) (Statewide Rule 78).
(4)
The Commission may plug or replug any dry or inactive well
as follows:
(A)
After notice and hearing, if the well is causing or is
likely to cause the pollution of surface or subsurface water or if oil or
gas is leaking from the well, and:
(i)
Neither the operator nor any other entity responsible for
plugging the well can be found; or
(ii)
Neither the operator nor any other entity responsible
for plugging the well has assets with which to plug the well.
(B)
Without a hearing if the well is a delinquent inactive
well and:
(i)
the Commission has sent notice of its intention to plug
the well as required by §89.043(c) of the Texas Natural Resources Code;
and
(ii)
the operator did not request a hearing within the period
(not less than 10 days after receipt) specified in the notice.
(C)
Without notice or hearing, if:
(i)
The Commission has issued a final order requiring that
the operator plug the well and the order has not been complied with; or
(ii)
The well poses an immediate threat of pollution of surface
or subsurface waters or of injury to the public health and the operator has
failed to timely remediate the problem.
(5)
The Commission may seek reimbursement from the operator
and any other entity responsible for plugging the well for state funds expended
pursuant to paragraph (4) of this subsection.
(c)
Designated operator responsible for proper plugging.
(1)
The entity designated as the operator of a well specifically
identified on the most recent Commission-approved operator designation form
filed on or after September 1, 1997, is responsible for properly plugging
the well in accordance with this section and all other applicable Commission
rules and regulations concerning plugging of wells.
(2)
As to any well for which the most recent Commission-approved
operator designation form was filed prior to September 1, 1997, the entity
designated as operator on that form is presumed to be the entity responsible
for the physical operation and control of the well and to be the entity responsible
for properly plugging the well in accordance with this section and all other
applicable Commission rules and regulations concerning plugging of wells.
The presumption of responsibility may be rebutted only at a hearing called
for the purpose of determining plugging responsibility.
(d)
General plugging requirements.
(1)
Wells shall be plugged to insure that all formations bearing
usable quality water, oil, gas, or geothermal resources are protected. All
cementing operations during plugging shall be performed under the direct supervision
of the operator or his authorized representative, who shall not be an employee
of the service or cementing company hired to plug the well. Direct supervision
means supervision at the well site during the plugging operations. The operator
and the cementer are both responsible for complying with the general plugging
requirements of this subsection and for plugging the well in conformity with
the procedure set forth in the approved notice of intention to plug and abandon
for the well being plugged. The operator and cementer may each be assessed
administrative penalties for failure to comply with the general plugging requirements
of this subsection or for failure to plug the well in conformity with the
approved notice of intention to plug and abandon the well.
(2)
Cement plugs shall be set to isolate each productive horizon
and usable quality water strata.
(3)
Cement plugs shall be placed by the circulation or squeeze
method through tubing or drill pipe. Cement plugs shall be placed by other
methods only upon written request with the written approval of the district
director or the director's delegate.
(4)
All cement for plugging shall be an approved API oil well
cement without volume extenders and shall be mixed in accordance with API
standards. Slurry weights shall be reported on the cementing report. The district
director or the director's delegate may require that specific cement compositions
be used in special situations; for example, when high temperature, salt section,
or highly corrosive sections are present.
(5)
Operators shall use only cementers approved by the assistant
director of well plugging or the assistant director's delegate, except when
plugging is conducted in accordance with subparagraph (B)(ii) of this paragraph
or paragraph (6) of this subsection. Cementing companies, service companies,
or operators may apply for designation as approved cementers. Approval will
be granted on a showing by the applicant of the ability to mix and pump cement
in compliance with this rule. An approved cementer is authorized to conduct
plugging operations in accordance with Commission rules in each Commission
district.
(A)
A cementing company, service company, or operator seeking
designation as an approved cementer shall file a request in writing with the
district director of the district in which it proposes to conduct its initial
plugging operations. The request shall contain the following information:
(i)
the name of the organization as shown on its most recent
approved organizational report;
(ii)
a list of qualifications including personnel who will
supervise mixing and pumping operations;
(iii)
length of time the organization has been in the business
of cementing oil and gas wells;
(iv)
an inventory of the type of equipment to be used to mix
and pump cement; and
(v)
a statement certifying that the organization will comply
with all Commission rules.
(B)
No request for designation as an approved cementer will
be approved until after the district director or the director's delegate has:
(i)
inspected all equipment to be used for mixing and pumping
cement; and
(ii)
witnessed at least one plugging operation to determine
if the cementing company, service company, or operator can properly mix and
pump cement to the specifications required by this rule.
(C)
The district director or the director's delegate shall
file a letter with the assistant director of well plugging recommending that
the application to be designated as an approved cementer be approved or denied.
If the district director or the director's delegate does not recommend approval,
or the assistant director of well plugging or the assistant director's delegate
denies the application, the applicant may request a hearing on its application.
(D)
Designation as an approved cementer may be suspended or
revoked for violations of Commission rules. The designation may be revoked
or suspended administratively by the assistant director of well plugging for
violations of Commission rules if:
(i)
the cementer has been given written notice by personal
service or by registered or certified mail informing the cementer of the proposed
action, the facts or conduct alleged to warrant the proposed action, and of
its right to request a hearing within 10 days to demonstrate compliance with
Commission rules and all requirements for retention of designation as an approved
cementer; and
(ii)
the cementer did not file a written request for a hearing
within 10 days of receipt of the notice.
(6)
An operator may request administrative authority to plug
its own wells without being an approved cementer. An operator seeking such
authority shall file a written request with the district director and demonstrate
its ability to mix and pump cement in compliance with this subsection. The
district director or the director's delegate will determine whether such a
request warrants approval. If the district director or the director's delegate
refuses to administratively approve this request, the operator may request
a hearing on its request.
(7)
The district director may require additional cement plugs
to cover and contain any productive horizon or to separate any water stratum
from any other water stratum if the water qualities or hydrostatic pressures
differ sufficiently to justify separation. The tagging and/or pressure testing
of any such plugs, or any other plugs, and respotting may be required if necessary
to insure that the well does not pose a potential threat of harm to natural
resources.
(8)
For onshore or inland wells, a 10-foot cement plug shall
be placed in the top of the well, and casing shall be cut off three feet below
the ground surface.
(9)
Mud-laden fluid of at least 9-1/2 pounds per gallon with
a minimum funnel viscosity of 40 seconds shall be placed in all portions of
the well not filled with cement. The hole shall be in static condition at
the time the cement plugs are placed. The district director may grant exceptions
to the requirements of this paragraph if a deviation from the prescribed minimums
for fluid weight or viscosity is necessary to insure that the well does not
pose a potential threat of harm to natural resources.
(10)
Non-drillable material that would hamper or prevent reentry
of a well shall not be placed in any wellbore during plugging operations,
except in the case of a well plugged and abandoned under the provisions of §3.35
or §3.94(e) of this title (relating to Procedures for Identification
and Control of Wellbores in Which Certain Logging Tools Have Been Abandoned
(Statewide Rule 35); and Disposal of Oil and Gas NORM Waste (Statewide Rule
94), respectively). Pipe and unretrievable junk shall not be cemented in the
hole during plugging operations without prior approval by the district director.
(11)
All cement plugs, except the top plug, shall have sufficient
slurry volume to fill 100 feet of hole, plus 10% for each 1,000 feet of depth
from the ground surface to the bottom of the plug.
(12)
The operator shall fill the rathole, mouse hole, and cellar,
and shall empty all tanks, vessels, related piping and flowlines that will
not be actively used in the continuing operation of the lease within 120 days
after plugging work is completed. Within the same 120 day period, the operator
shall remove all such tanks, vessels, related surface piping, and all subsurface
piping that is less than three feet beneath the ground surface, remove all
loose junk and trash from the location, and contour the location to discourage
pooling of surface water at or around the facility site. The operator shall
close all pits in accordance with the provisions of §3.8 of this title
(relating to Water Protection (Statewide Rule 8)). The district director may
grant a reasonable extension of time of not more than an additional 120 days
for the removal of tanks, vessels and related piping.
(e)
Plugging requirements for wells with surface casing.
(1)
When insufficient surface casing is set to protect all
usable quality water strata and such usable quality water strata are exposed
to the wellbore when production or intermediate casing is pulled from the
well or as a result of such casing not being run, a cement plug shall be placed
from 50 feet below the base of the deepest usable quality water stratum to
50 feet above the top of the statum. This plug shall be evidenced by tagging
with tubing or drill pipe. The plug must be respotted if it has not been properly
placed. In addition, a cement plug must be set across the shoe of the surface
casing. This plug must be a minimum of 100 feet in length and shall extend
at least 50 feet above and below the shoe.
(2)
When sufficient surface casing has been set to protect
all usable quality water strata, a cement plug shall be placed across the
shoe of the surface casing. This plug shall be a minimum of 100 feet in length
and shall extend at least 50 feet above the shoe and at least 50 feet below
the shoe.
(3)
If surface casing has been set deeper than 200 feet below
the base of the deepest usable quality water stratum, an additional cement
plug shall be placed inside the surface casing across the base of the deepest
usable quality water stratum. This plug shall be a minimum of 100 feet in
length and shall extend from 50 feet below the base of the deepest usable
quality water stratum to 50 feet above the top of the stratum.
(f)
Plugging requirements for wells with intermediate casing.
(1)
For wells in which the intermediate casing has been cemented
through all usable quality water strata and all productive horizons, a cement
plug meeting the requirements of subsection (d)(11) of this section shall
be placed inside the casing and centered opposite the base of the deepest
usable quality water stratum, but extend no less than 50 feet above and below
the stratum.
(2)
For wells in which intermediate casing is not cemented
through all usable quality water strata and all productive horizons, and if
the casing will not be pulled, the intermediate casing shall be perforated
at the required depths to place cement outside of the casing by squeeze cementing
through casing perforations.
(g)
Plugging requirements for wells with production casing.
(1)
For wells in which the production casing has been cemented
through all usable quality water strata and all productive horizons, a cement
plug meeting the requirements of subsection (d)(11) of this section shall
be placed inside the casing and centered opposite the base of the deepest
usable quality water stratum and across any multi-stage cementing tool.
(2)
For wells in which the production casing has not been cemented
through all usable quality water strata and all productive horizons and if
the casing will not be pulled, the production casing shall be perforated at
the required depths to place cement outside of the casing by squeeze cementing
through casing perforations.
(3)
The district director may approve a cast iron bridge plug
to be placed immediately above each perforated interval, provided at least
20 feet of cement is placed on top of each bridge plug. A bridge plug shall
not be set in any well at a depth where the pressure or temperature exceeds
the ratings recommended by the bridge plug manufacturer.
(h)
Plugging requirements for well with screen or liner.
(1)
If practical, the screen or liner shall be removed from
the well.
(2)
If the screen or liner is not removed, a cement plug in
accordance with subsection (d)(11) of this section shall be placed at the
top of the liner.
(i)
Plugging requirements for wells without production casing
and open-hole completions.
(1)
Any productive horizon or any formation in which a pressure
or formation water problem is known to exist shall be isolated by cement plugs
centered at the top and bottom of the formation. Each cement plug shall have
sufficient slurry volume to fill a calculated height as specified in subsection
(d)(11) of this section.
(2)
If the gross thickness of any such formation is less than
100 feet, the tubing or drill pipe shall be suspended 50 feet below the base
of the formation. Sufficient slurry volume shall be pumped to fill the calculated
height from the bottom of the tubing or drill pipe up to a point at least
50 feet above the top of the formation, plus 10% for each 1,000 feet of depth
from the ground surface to the bottom of the plug.
(j)
The district director shall review and approve the notification
of intention to plug in a manner so as to accomplish the purposes of this
section. The district director may approve, modify, or reject the operator's
notification of intention to plug. If the proposal is modified or rejected,
the operator may request a review by the director of field operations. If
the proposal is not administratively approved, the operator may request a
hearing on the matter. After hearing, the examiner shall recommend final action
by the Commission.
(k)
Plugging horizontal drainhole wells. All plugs in horizontal
drainhole wells shall be set in accordance with subsection (d)(11) of this
section. The productive horizon isolation plug shall be set from a depth 50
feet below the top of the productive horizon to a depth either 50 feet above
the top of the productive horizon, or 50 feet above the production casing
shoe if the production casing is set above the top of the productive horizon.
If the production casing shoe is set below the top of the productive horizon,
then the productive horizon isolation plug shall be set from a depth 50 feet
below the production casing shoe to a depth that is 50 feet above the top
of the productive horizon. In accordance with subsection (d)(7) of this section,
the Commission or its delegate may require additional plugs.
§3.78.Fees, Performance Bonds and Alternate Forms of Financial Security Required To Be Filed.
(a)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise:
(1)
Violation--Noncompliance with a Commission rule, order,
license, permit, or certificate relating to safety or the prevention or control
of pollution.
(2)
Outstanding violation--A violation for which:
(A)
either:
(i)
a Commission order finding a violation has been entered
and all appeals have been exhausted; or
(ii)
an agreed order between the Commission and the organization
relating to a violation has been entered; and
(B)
one or more of the following conditions still exist:
(i)
the conditions that constituted the violation have not
been corrected;
(ii)
all administrative, civil, and criminal penalties, if
any, relating to the violation of such Commission rules, orders, licenses,
permits, or certificates have not been paid; or
(iii)
all reimbursements of any costs and expenses assessed
by the Commission relating to the violation of such Commission rules, orders,
licenses, permits, or certificates have not been paid.
(3)
An acceptable record of compliance--
(A)
A record of compliance showing:
(i)
No enforcement orders issued; and
(ii)
No outstanding violations; or
(B)
A record of compliance showing:
(i)
Only one enforcement order, provided the order specifies
that it shall not be considered to meet the elements of subparagraph (A) of
this definition and provided the requirements of the order are met;
(ii)
No enforcement orders issued other than those that are
resolved in the order referenced in clause (i) of this subparagraph;
(iii)
No outstanding violations other than those resolved in
the order referenced in clause (i) of this subparagraph.
(4)
Commercial facility--A facility whose owner or operator
receives compensation from others for the storage, reclamation, treatment,
or disposal of oil field fluids or oil and gas wastes that are wholly or partially
trucked or hauled to the facility and whose primary business purpose is to
provide these services for compensation if:
(A)
the facility is permitted under §3.8 of this title
(relating to Water Protection);
(B)
the facility is permitted under §3.57 of this title
(relating to Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other
Waste Materials);
(C)
the facility is permitted under §3.9 of this title
(relating to Disposal Wells) and a collecting pit permitted under §3.8
is located at the facility; or
(D)
the facility is permitted under §3.46 of this title
(relating to Fluid Injection into Productive Reservoirs) and a collecting
pit permitted under §3.8 is located at the facility.
(5)
Financial security--An individual performance bond, blanket
performance bond, letter of credit, or cash deposit filed with the Commission.
(6)
Alternate form of financial security--Payment of a nonrefundable
annual fee to the Commission.
(7)
Individual well bond A bond or letter of credit issued:
(A)
on a Commission-approved form;
(B)
by a third party surety, insurance company, or financial
institution approved by the Commission; and
(C)
to secure the timely and proper plugging of a specified
well and remediation of the wellsite, in accordance with Commission rules.
(8)
Bay well--Any well under the jurisdiction of the Commission
for which the surface location is either:
(A)
located in or on a lake, river, stream, canal, estuary,
bayou, or other inland navigable waters of the state; or,
(B)
located on state lands seaward of the mean high tide line
of the Gulf of Mexico in water of a depth at mean high tide of not more than
100 feet that is sheltered from the direct action of the open seas of the
Gulf of Mexico.
(9)
Land well--Any well subject to Commission jurisdiction
for which the surface location is not in or on inland or coastal waters.
(10)
Offshore well--Any well subject to Commission jurisdiction
for which the surface location is on state lands in or on the Gulf of Mexico,
that is not a bay well.
(b)
Filing fees. The following filing fees are required to
be paid to the Railroad Commission.
(1)
With each application or materially amended application
for a permit to drill, deepen, plug back, or reenter a well, the applicant
shall submit to the Commission a nonrefundable fee of:
(A)
$200 if the proposed total depth of the well is 2,000 feet
or less;
(B)
$225 if the proposed total depth of the well is greater
than 2,000 feet but less than or equal to 4,000 feet;
(C)
$250 if the proposed total depth of the well is greater
than 4,000 feet but less than or equal to 9,000 feet; or
(D)
$300 if the proposed total depth of the well is greater
than 9,000 feet.
(2)
An application for a permit to drill, deepen, plug back,
or reenter a well will be considered materially amended if the amendment is
made for a purpose other than:
(A)
to add omitted required information;
(B)
to correct typographical errors;
(C)
to correct clerical errors.
(3)
An applicant shall submit an additional nonrefundable fee
of $150 when requesting that the Commission expedite the application for a
permit to drill, deepen, plug back, or reenter a well.
(4)
With each individual application for an exception to any
rule or rules in this chapter, the applicant shall submit to the Commission
a nonrefundable fee of $150, except as provided in paragraph (5) of this subsection.
(5)
With each application for an exception to any rule or rules
in this chapter that includes an exception to §3.37 of this title (relating
to Statewide Spacing Rule) (Statewide Rule 37) or §3.38 of this title
(relating to Well Densities) (Statewide Rule 38), the applicant shall submit
a nonrefundable fee of $200.
(6)
With each application for an extension of time to plug
a well pursuant to Commission rules, an applicant who has filed an alternate
form of financial security as provided for under this rule, shall submit to
the Commission a nonrefundable fee of $300.
(7)
With each application for an oil and gas waste disposal
well permit, the applicant shall submit to the Commission a nonrefundable
fee of $100 per well.
(8)
With each application for a fluid injection well permit,
the applicant shall submit to the Commission a nonrefundable fee of $200 per
well. Fluid injection well means any well used to inject fluid or gas into
the ground in connection with the exploration or production of oil or gas
other than an oil and gas waste disposal well.
(9)
With each application for a permit to discharge to surface
water other than a permit for a discharge that meets national pollutant discharge
elimination system (NPDES) requirements for agricultural or wildlife use,
the applicant shall submit to the Commission a nonrefundable fee of $300.
(10)
If a certificate of compliance has been canceled, the
operator shall submit to the Commission a nonrefundable fee of $100 before
the Commission may reissue the certificate pursuant to §3.58 of this
title (relating to Oil, Gas, or Geothermal Resource Producer's Reports) (Statewide
Rule 58).
(11)
With each application for issuance, renewal, or material
amendment of an oil and gas waste hauler's permit, the applicant shall submit
to the Commission a nonrefundable fee of $100.
(12)
With each Natural Gas Policy Act (15 United States Code §§3301-3432)
application, the applicant shall submit to the Commission a nonrefundable
fee of $150.
(13)
Hazardous waste generation fee. A person who generates
hazardous oil and gas waste, as that term is defined in §3.98 of this
title (relating to Standards for Management of Hazardous Oil and Gas Waste),
shall pay to the Commission the fees specified in §3.98(z).
(14)
A check or money order for any of the aforementioned fees
shall be made payable to the Railroad Commission of Texas. If the check accompanying
an application is not honored upon presentment, the permit issued on the basis
of that application, the allowable assigned, the exception to a statewide
rule granted on the basis of the application, the extension of time to plug
a well, or the Natural Gas Policy Act category determination made on the basis
of the application may be suspended or revoked.
(15)
If an operator submits a check that is not honored on
presentment, the operator shall, for a period of 24 months after the check
was presented, submit any payments in the form of a credit card, cashier's
check, or cash.
(c)
Organization Report Fee. An organization report required
by Texas Natural Resources Code, §91.142, shall be accompanied by a fee
as follows:
(1)
for an operator of:
(A)
not more than 25 wells, $300;
(B)
more than 25 but not more than 100 wells, $500; or
(C)
more than 100 wells, $1,000;
(2)
for an operator of one or more natural gas pipelines, $100;
(3)
for an operator of one or more of the following service
activities: pollution cleanup contractor; directional surveying; approved
cementer for plugging wells; or physically moving or storing crude or condensate,
$300;
(4)
for an operator of all other service activities or facilities,
including liquids pipelines, $500;
(5)
for an operator of wells who also operates one or more
service activities, facilities, or pipelines as classified by the Commission,
the sum of the fees that would be separately charged for each category of
service activity, facility, pipeline, or number or wells operated, provided
that such fee shall not exceed $1,000; or
(6)
for an entity not currently performing operations under
the jurisdiction of the Commission, $300.
(d)
Financial security and alternate forms of financial security.
Any person, including any firm, partnership, joint stock association, corporation,
or other organization, required by Texas Natural Resources Code, §91.142,
to file an organization report with the Commission must also file financial
security in one of the following forms:
(1)
an individual performance bond;
(2)
a blanket performance bond;
(3)
a nonrefundable annual fee of $1,000, if:
(A)
the Commission determines that individual and blanket performance
bonds as specified by this section are not obtainable at reasonable prices
as provided for under subsection (f) of this section;
(B)
the person can demonstrate to the Commission an acceptable
record of compliance with all Commission rules, orders, licenses, permits,
or certificates that relate to safety or the prevention or control of pollution
for the previous 48 months and the person has no outstanding violations; and
(C)
if the person is a firm, partnership, joint stock association,
corporation, or other organization, its officers, directors, general partners,
or owners of more than 25% ownership interest or any trustee must also not
have any outstanding violations.
(4)
a nonrefundable annual fee equal to 12.5% of the face amount
of the performance bond that otherwise would be required; or
(5)
a letter of credit or cash deposit in the same amount as
required for an individual performance bond or blanket performance bond.
(e)
Eligibility for nonrefundable $1,000 fee.
(1)
For the purposes of this subsection, "officers and owners"
include directors, general partners, owners of more than 25% ownership interest,
or any trustee of an organization.
(2)
A person filing an organization report for the first time
in order to perform any Commission-regulated operations is a new organization
and is not eligible to file the nonrefundable fee of $1,000.
(3)
A person who filed an initial organization report less
than 48 months prior to the current filing is not eligible to file the nonrefundable
fee of $1,000.
(4)
A change in name, without any other organizational change,
of a person registered with the Commission does not indicate a new organization.
If the Commission determines that only a name change has occurred, then a
person operating under a new name may file the nonrefundable fee of $1,000
if the person meets all other eligibility requirements.
(5)
An individual registered with the Commission as a sole
proprietor or who is a general partner of a partnership that is registered
with the Commission and who reorganizes his or her oil and gas operations
under a new legal entity or establishes a new and separate entity will be
considered to have satisfied the 48- month eligibility requirement for filing
the nonrefundable fee of $1,000.
(6)
A surviving or new corporation or other entity resulting
from a merger under the Texas Business Corporation Act, Part Five, may file
the nonrefundable fee of $1,000 if:
(A)
the existing record of compliance for each entity that
is a party to the merger qualifies;
(B)
the records of compliance for the officers and owners of
the surviving or new entities qualify; and
(C)
the number of surviving or new entities eligible does not
exceed the number of parties registered with the Commission at the time of
the merger.
(7)
In any Commission enforcement proceeding, if a person is
determined not to be the responsible party for a violation and is dismissed
from the proceeding for that reason, that violation shall not be considered
in determining whether that person has an acceptable record of compliance.
(f)
Availability of bonds.
(1)
In determining the applicability of the $1,000 nonrefundable
fee as provided for under this section, the Commission presumes that individual
and blanket performance bonds are obtainable at reasonable prices.
(2)
An operator may request a hearing to determine that individual
and blanket performance bonds are not obtainable at reasonable prices. In
order to support a determination that bonds are not obtainable at reasonable
prices, the operator must show:
(A)
that no fewer than three companies which have issued a
bond filed with the Commission in the past 12 months will not issue a bond
to the requesting operator for an annual fee less than 12% of the face amount
of the bond; and
(B)
that the operator is otherwise eligible under this section
to file a $1,000 nonrefundable annual fee.
(g)
Forms for financial security. Operators shall submit bonds
and letters of credit on forms prescribed by the Commission.
(h)
Filing deadlines for financial security. Operators shall
submit required financial security at the time of filing an initial organization
report or upon yearly renewal, or as required under subsection (m) of this
section.
(i)
New operators. A person filing an organization report for
the first time is a new organization and is not eligible to file an individual
performance bond for the first year of operation.
(j)
Amount of bond, letter of credit, or cash deposit.
(1)
A person who operates one or more wells may file an individual
performance bond, letter of credit or cash deposit in an amount equal to $2.00
for each foot of total well depth for each well, plus an additional amount
to be determined by the Commission in a subsequent rulemaking for each bay
and offshore well operated.
(2)
A person operating wells may file a blanket bond, letter
of credit or cash deposit to cover all wells for which a bond, letter of credit
or cash deposit is required in an amount equal to the sum of:
(A)
A base amount determined by the total number of wells operated,
as follows:
(i)
a person who operates 10 or fewer wells or performs other
operations shall have a base amount of $25,000;
(ii)
a person who operates more than 10 but fewer than 100
wells shall have a base amount of $50,000; and
(iii)
a person who operates 100 or more wells shall have a
base amount of $250,000, plus;
(B)
an additional amount, to be determined by the Commission
in a subsequent rulemaking, for each bay well operated, plus
(C)
an additional amount, to be determined by the Commission
in a subsequent rulemaking, for each offshore well operated.
(3)
A person operating wells and performing other operations,
who chooses to cover all operations by a blanket performance bond, letter
of credit or cash deposit shall file a bond, letter of credit or cash deposit
in an amount determined by the total number of wells, but not less than $25,000.
Only one blanket performance bond, letter of credit or cash deposit is required
for a person performing multiple operations, unless the person is operating
a commercial facility subject to the financial security requirements of subsection
(p) of this section.
(4)
Financial security amounts are the minimum amounts required
by this section to be filed. A person may file a greater amount if desired.
(k)
Bond Conditions. Any financial security required under
this section is subject to the conditions that the operator will plug and
abandon all wells and control, abate, and clean up pollution associated with
the oil and gas operations and activities covered under the required financial
security in accordance with applicable state law and permits, rules, and orders
of the Commission.
(l)
Conditions for cash deposits. Operators shall tender cash
deposits in United States currency or certified cashiers check only. All cash
deposits will be placed in a special account within the Oil Field Clean Up
Fund account. Any interest accruing on cash deposits will be deposited into
the Oil Clean Up Fund pursuant to Texas Natural Resources Code, §91.111(c)(8).
The Commission will not refund a cash deposit until either financial security
or an alternate form of financial security is accepted by the Commission as
provided for under this section or an operator ceases all activity.
(m)
Individual well bonds.
(1)
An operator who has filed an alternate form of financial
security with the Commission and who applies for a plugging extension for
a well that has been inactive for more than 36 months is required under §3.14
of this title (relating to Plugging) to file an individual well bond or individual
well letter of credit in the face amount of the estimated plugging cost of
the well for which a plugging extension is requested. The Commission shall
presume that the estimated plugging cost for wells for which a plugging extension
is sought is as follows:
(A)
for land wells, the product of the total depth of the well
multiplied by $3 per foot;
(B)
for bay wells, $60,000; and,
(C)
for offshore wells, $250,000.
(2)
An operator may rebut the presumed estimated plugging costs
for a specific well for which a plugging extension is sought at hearing by
clear and convincing evidence establishing a higher or lower prospective plugging
cost for the well. The operator, Commission staff, or any owner of the surface
or mineral estate on which the well is located may initiate a hearing on the
prospective plugging cost for a well for the purpose of setting the amount
of an individual well bond by filing a request for hearing.
(3)
If an individual well bond is required, it shall be continuously
maintained until the well is plugged or returned to active operation, as defined
under §3.14, unless the operator files financial security as provided
by this section.
(n)
Well or lease transfer.
(1)
The Commission shall not approve a transfer of operatorship
submitted for any well or lease unless the operator acquiring the well or
lease has on file with the Commission one of the following approved forms
of financial security in an amount sufficient to cover both its current operations
and the wells being transferred:
(A)
an individual performance bond, letter of credit or cash
deposit; or
(B)
a blanket performance bond, letter of credit or cash deposit.
(2)
Any existing financial security or individual well bond
covering the well or lease proposed for transfer shall remain in effect and
the prior operator of the well remains responsible for compliance with all
laws and Commission rules covering the transferred well until the Commission
approves the transfer.
(3)
A transfer of a well or lease from one entity to another
entity under common ownership is a transfer for the purposes of this section.
(o)
Reimbursement liability. Filing any form of financial security
does not extinguish a person's liability for reimbursement for the expenditure
of state oilfield clean-up funds pursuant to the Texas Natural Resources Code, §89.083
and §91.113.
(p)
Financial security for commercial facilities. The provisions
of this subsection shall apply to the holder of any permit for a commercial
facility.
(1)
Application.
(A)
New permits. Any application for a new or amended commercial
facility permit filed after the original effective date of this subsection
shall include:
(i)
a written estimate of the maximum dollar amount necessary
to close the facility prepared in accordance with the provisions of paragraph
(4) of this subsection that shows all assumptions and calculations used to
develop the estimate;
(ii)
a copy of the form of the bond or letter of credit that
will be filed with the Commission; and
(iii)
information concerning the issuer of the bond or letter
of credit as required under paragraph (5) of this subsection including the
issuer's name and address and evidence of authority to issue bonds or letters
of credit in Texas.
(B)
Existing permits. Within 180 days of the original effective
date of this subsection, the holder of any commercial facility permit issued
on or before the original effective date of this subsection shall file with
the Commission the information specified in subparagraph (A)(i)-(iii) of this
paragraph.
(2)
Notice and hearing.
(A)
New permits. For commercial facility permits issued after
the original effective date of this subsection, the provisions of §3.8
or §3.57 of this title (relating to Water Protection; and Reclaiming
Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste Materials), as applicable,
regarding notice and opportunity for hearing, shall apply to review and approval
of financial security proposed to be filed to meet the requirements of this
subsection.
(B)
Existing permits. Notice of filing of information required
under paragraph (1)(B) of this subsection shall not be required. In the event
approval of the financial security proposed to be filed for a commercial facility
operating under a permit in effect as of the original effective date of this
subsection is denied administratively, the applicant shall have the right
to a hearing upon written request. After hearing, the examiner shall recommend
a final action by the Commission.
(3)
Filing of instrument.
(A)
New permits. A commercial facility permitted after the
original effective date of this subsection may not receive oil field fluids
or oil and gas waste until a bond or letter of credit in an amount approved
by the Commission or its delegate under this subsection and meeting the requirements
of this subsection as to form and issuer has been filed with the Commission.
(B)
Existing permits. Except as otherwise provided in this
subsection, after one year from the original effective date of this section,
a commercial facility permitted on or before the original effective date of
this subsection may not continue to receive oil field fluids or oil and gas
waste unless a bond or letter of credit in an amount approved by the Commission
or its delegate under this subsection and meeting the requirements of this
subsection as to form and issuer has been filed with and approved by the Commission
or its delegate.
(C)
Extensions for existing permits. On written request and
for good cause shown, the Commission or its delegate may authorize a commercial
facility permitted before the original effective date of this subsection to
continue to receive oil field fluids or oil and gas waste after one year after
the original effective date of this section even though financial security
required under this subsection has not been filed. In the event the Commission
or its delegate has not taken final action to approve or disapprove the amount
of financial security proposed to be filed by the owner or operator under
this subsection one year after the original effective date of the section,
the period for filing financial security under this subsection is automatically
extended to a date 45 days after such final Commission action.
(4)
Amount.
(A)
Except as provided in subparagraphs (B) or (C) of this
paragraph, the amount of financial security required to be filed under this
subsection shall be an amount based on a written estimate approved by the
Commission or its delegate as being equal to or greater than the maximum amount
necessary to close the commercial facility, exclusive of plugging costs for
any well or wells at the facility, at any time during the permit term in accordance
with all applicable state laws, Commission rules and orders, and the permit,
but shall in no event be less than $10,000.
(B)
The owner or operator of a commercial facility may reduce
the amount of financial security required under this subsection by $25,000
if the owner or operator holds only one commercial facility permit.
(C)
The owner or operator of more than one commercial facility
may reduce the amount of financial security required under this subsection
for one such facility by $25,000. The full amount of financial security required
under subparagraph (A) of this paragraph shall be required for the remaining
commercial facilities.
(D)
Except for the facilities specifically exempted under subparagraph
(E), a qualified professional engineer licensed by the State of Texas shall
prepare or supervise the preparation of a written estimate of the maximum
amount necessary to close the commercial facility as provided in subparagraph
(A) of this paragraph. The owner or operator of a commercial facility shall
submit the written estimate under seal of a qualified licensed professional
engineer to the Commission as required under paragraph (1) of this subsection.
(E)
A facility permitted under §3.57 of this title (relating
to Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste Materials)
that does not utilize on-site waste storage or disposal that requires a permit
under §3.8 of this title (relating to Water Protection) is exempt from
subparagraph (D) of this paragraph.
(F)
Notwithstanding the fact that the maximum amount necessary
to close the commercial facility as determined under this paragraph is exclusive
of plugging costs, the proceeds of financial security filed under this subsection
may be used by the Commission to pay the costs of plugging any well or wells
at the facility if the financial security for plugging costs filed with the
Commission is insufficient to pay for the plugging of such well or wells.
(5)
Issuer and form.
(A)
Bond. The issuer of any commercial facility bond filed
in satisfaction of the requirements of this subsection shall be a corporate
surety authorized to do business in Texas. The form of bond filed under this
subsection shall provide that the bond be renewed and continued in effect
until the conditions of the bond have been met or its release is authorized
by the Commission or its delegate.
(B)
Letter of credit. Any letter of credit filed in satisfaction
of the requirements of this subsection shall be issued by and drawn on a bank
authorized under state or federal law to operate in Texas. The letter of credit
shall be an irrevocable, standby letter of credit subject to the requirements
of Texas Business and Commerce Code, §§5.101-5.118. The letter of
credit shall provide that it will be renewed and continued in effect until
the conditions of the letter of credit have been met or its release is authorized
by the Commission or its delegate.
This agency hereby certifies that the adoption
has been reviewed by legal counsel and found to be a valid exercise of the
agency's legal authority.
Filed with the Office of
the Secretary of State on December 20, 2001.
TRD-200108167
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: November 9, 2001
For further information, please call: (512) 463-7008
16 TAC §3.40
The Railroad Commission of Texas adopts amendments to §3.40,
relating to Assignment of Acreage to Pooled Development and Proration Units,
with changes to the proposal published in the October 5, 2001, issue of the
The Commission simultaneously adopts the review and readoption of §3.40,
as amended, in accordance with Texas Government Code, §2001.039 (
The Commission received no comments on the proposed amendment or rule review
from a group or association; the commission received one comment that made
several points.
The first point in the comment concerns the proposed wording in subsection
(a), which provides that an operator may pool acreage, up to the acreage limits
specified in applicable field rules, into a development or proration unit
by filing an original certified plat delineating the pooled unit and a Certificate
of Pooling Authority, Form P-12 (revised 5/2001), according to the requirements
set out in the remainder of the paragraphs. The comment notes that the proposed
wording is not a substantial change to the existing language, but suggests
that it be revised to eliminate any implication that the Commission's field
rules may override the contractual authority of operators to form pooled units
pursuant to their oil and gas leases or other private agreements, because
the Commission's authority is limited to conservation matters. The comment
concedes that the Commission may limit the amount of acreage that may be assigned
to wells for proration and allowable purposes. The comment also noted that
the term "development unit" is undefined in Commission rules, and proposed
alternative wording that would eliminate the term.
The Commission notes that the wording of the current rule includes a reference
to the Commission's field rules, does not contain any reference to "appropriate
contractual authority," and uses both "development unit" and "proration unit."
The Commission is unaware of any problems interpreting or applying §3.40
because of the current wording, but agrees that it is preferable not to use
undefined terms in its rules. The Commission has clarified the wording in §3.40(a)
to eliminate the term "development unit" and to include a reference to the
contractual source of an operator's authority to pool.
A second point in the comment concerns the wording in §3.40(a)(2)(A),
which provides that as part of the information filed under the rule, the operator
must separately list each tract that is to be pooled by authority of an agreement
between the various interest holders in the several tracts committed to the
unit. The comment states that under normal circumstances, the various royalty
interest-owning interests within different tracts of a pooled unit do not
agree among themselves to pooling authority. Instead, these lessor/royalty
owners and/or working interest owners grant pooling authority to their lessees/operators
in oil and gas leases, joint operating agreements, or by other contractual
agreements. The comment suggested alternative wording.
The Commission notes that the wording "tracts are pooled by authority of
an agreement between the various interest holders in the several tracts committed
to the unit," is part of the current wording of the rule. The Commission is
unaware of any difficulties or problems caused by this language; nevertheless,
the comment's suggested wording is more succinct and is a clearer statement
of the Commission's intent with respect to the operation of this requirement.
The Commission has adopted this alternative wording.
A third point in the comment concerns wording in §3.40(a)(2)(B), which
requires an operator to state, for each tract listed on Form P-12, the number
of acres contained within the tract and to indicate, by checking the appropriate
box on Form P-12 if, within an individual tract, there exists a non-pooled
and/or unleased interest. The comment objects to identifying unleased interests
and states that the Commission's only concern should be whether a tract within
a pooled unit contains a non-pooled interest; whether such a tract contains
an unleased interest is relevant only if the unleased interest is also not
pooled. The comment continues that there are situations in which the unleased
interest owners have agreed to pool, thereby removing the Commission's concern
for the protection of such interests's correlative rights. The comment offered
alternative wording that eliminates the requirement to identify unleased interests
on Form P-12.
The Commission disagrees with this comment, because both pieces of information
about a tract are necessary. If the operator/applicant is placing a well within
the distance limits governed by the provisions of §3.37, relating to
Statewide Spacing Rule, where there is an unleased interest, the operator/applicant
must give notice to the holder of the unleased interest. For this reason,
the Commission declines to make the change suggested in the comment.
A fourth point in the comment objects to language in §3.40(a)(2)(E)
that would require an operator to provide the requested identification and
"contract" information on the Form P-12. The Commission notes that this is
a typographical error, and the requirement is to provide "contact" information.
The correction has been made in the rule text.
The fifth point in the comment concerns the proposed amendment in §3.40(a)(5)(A),
which requires an operator to file the Form P-12 and certified plat with the
drilling permit application when two or more tracts are pooled to form a pooled
unit to obtain a drilling permit. The comment points out that this language,
and specifically the words "are pooled," may imply that a pooled unit must
actually be formed, normally by the filing of an appropriate pooled unit designation
in the courthouse, before the drilling permit application is filed with the
Commission. The Commission's long-standing custom and practice has not been
to require that pooled units actually be formed prior to permitting a well
on a pooled-unit basis; most oil and gas leases authorize the formation of
pooled units either before or after the drilling of a well. The comment further
observed that changing the Commission's policy does not serve any conservation
purpose and may impede the ability of operators to drill and develop their
acreage and to form pooled units on the basis of more definitive geology after
wells have been drilled. The comment offered alternative language for this
subparagraph.
The Commission points out that the current wording of §3.40(a) includes
the phraseology to which the comment objects; nevertheless, the Commission
agrees that clarification of the proposed wording in §3.40(a)(5)(A) is
appropriate. The Commission adopts slightly different wording from that suggested
in the comment.
Sixth, the comment noted that proposed §3.40(a)(5)(C) is not clear
whether the Form P-12 must be filed whenever a pooled unit is changed, even
if no pooled unit has been previously recognized by the Commission, or only
when the pooled unit has been previously designated at the Commission. The
comment further observed that the Commission historically has not been concerned
with the manner in which operators pooled their leases and acreage unless
such pooling related to some conservation purpose. The comment urged retention
of this policy and unnecessary filings of Form P-12 avoided for pooled units
not previously recognized by the Commission and having no regulatory significance.
The comment provided substitute wording.
Again, the Commission agrees that clarification in §3.40(a)(5) is
necessary, but has adopted slightly different wording from that offered by
the comment.
Finally, the comment twice made the point that the proposed amendment is
much more specific than most Commission rules as it relates to the identification,
version, and content of a Commission form (P-12). The comment stated that
such specificity may raise questions whether any revision to the Form P-12
will require a rulemaking.
The Commission recognizes that form revisions may be necessary
periodically to improve the format, or to add or delete information to be
reported on the form. The Commission intends to make these changes part of
rulemaking proceedings so that all interested persons--the general public
as well as the industry-- can have notice of proposed changes in agency regulatory
policy and an opportunity to participate, consistent with the notice and comment
procedures in Tex. Gov't Code, Chapter 2001.
The Commission adopts the amendments pursuant to Texas Natural Resources
Code, §§81.051 and 81.052, which provide the Commission with jurisdiction
over all persons owning or engaged in drilling or operating oil or gas wells
in Texas and the authority to adopt all necessary rules for governing and
regulating persons and their operations under the jurisdiction of the Commission;
and Texas Natural Resources Code, Chapter 102, which gives the Commission
the authority to establish pooled units for the purpose of avoiding the drilling
of unnecessary wells, protecting correlative rights, or preventing waste.
Texas Natural Resources Code, Chapter 102, is affected by the amendments.
Issued in Austin, Texas, on December 20, 2001.
§3.40.Assignment of Acreage to Pooled Development and Proration Units.
(a)
An operator may pool acreage, in accordance with appropriate
contractual authority and applicable field rules, for the purpose of creating
a drilling unit or proration unit by filing an original certified plat delineating
the pooled unit and a Certificate of Pooling Authority, Form P-12 (revised
5/2001), according to the following requirements:
(1)
Each tract in the certified plat shall be identified with
an outline and a tract identifier that corresponds to the tract identifier
listed on the Form P-12.
(2)
The operator shall provide information on the Certificate
of Pooling Authority, Form P-12, accurately and according to the instructions
on the form.
(A)
The operator shall separately list each tract committed
to the pooled unit by authority granted to the operator.
(B)
For each tract listed on Form P-12, the operator shall
state the number of acres contained within the tract. The operator shall indicate
by checking the appropriate box on Form P-12 if, within an individual tract,
there exists a non-pooled and/or unleased interest.
(C)
The operator shall state on Form P-12 the total number
of acres in the pooled unit. The total number of acres in the pooled unit
shall equal the sum of all acres in each individual tract listed.
(D)
If a pooled unit contains more tracts than can be listed
on a single Form P-12, the operator shall file as many additional Forms P-12
as necessary to list each pooled tract individually. The additional Forms
P-12 shall be numbered in sequence.
(E)
The operator shall provide the requested identification
and contact information on the Form P-12.
(F)
The operator shall certify the information on the Form
P-12 by signing and dating the form.
(3)
Failure to timely file the required information on the
certified plat or the Form P-12 may result in the dismissal of the W-1 application.
"Timely" means within three months of the Commission notifying the operator
of the need for additional information on the certified plat and/or the Form
P-12.
(4)
The operator shall file the original certified plat and
Form P-12 at the Commission's Austin office. The operator shall file a copy
of the certified plat and Form P-12 with the appropriate Commission district
office or offices. If the operator files electronically through the Commission's
Electronic Compliance and Approval Process (ECAP) system, the operator is
not required to file additional paper copies in the appropriate Commission
district office, because all Commission offices will have electronic access
to the Form P-12 and certified plat.
(5)
The operator shall file the Form P-12 and certified plat:
(A)
with the drilling permit application when two or more tracts
are joined to form a pooled unit for Commission purposes to obtain a drilling
permit;
(B)
with completion paperwork when the pooled unit's acreage
is being used or assigned for allowable purposes;
(C)
to designate a pooled unit formed after completion paperwork
has been filed when the pooled unit's acreage is being used or assigned for
allowable purposes; or
(D)
to designate a change in a pooled unit previously recognized
by the Commission. The operator shall file any changes to a pooled unit in
accordance with the requirements of §3.38(d)(3) of this title, relating
to Well Densities.
(b)
If a tract to be pooled has an outstanding interest for
which pooling authority does not exist, the tract may be assigned to a unit
where authority exists in the remaining undivided interest, provided, that
total gross acreage in the tract is included for allocation purposes, and
the certificate filed with the commission shows that a certain undivided interest
is outstanding in the tract. The commission will not allow an operator to
assign only his undivided interest out of a basic tract, where a nonpooled
interest exists.
(c)
The nonpooled undivided interest holder retains his development
rights in his basic tract, and should such rights be exercised, authority
to develop the basic tract be approved by the commission, and a well completed
as a producer thereon, then the entire interest in the basic tract must be
allocated to said well, and any interest insofar as it is pooled with another
tract must be assigned to the well on the basic tract for allocation purposes.
Splitting of undivided interest in a basic tract between two or more wells
on two or more tracts is not acceptable.
(d)
Acreage assigned to a well for drilling and development,
or for allocation of allowable, shall not be assigned to any other well or
wells projected to or completed in the same reservoir; such duplicate assignment
of acreage is not acceptable, provided, however, that this limitation shall
not prevent the reformation of development or proration units so long as no
duplicate assignment of acreage occurs, and further, that such reformation
does not violate other conservation regulations.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on December 20, 2001.
TRD-200108169
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: October 5, 2001
For further information, please call: (512) 463-7008
16 TAC §3.73
The Railroad Commission of Texas adopts the repeal of §3.73,
relating to Inscriptions on Railroad Commission of Texas Vehicles, without
changes to the proposal published in the November 9, 2001, issue of the
The Commission concurrently filed a notice of intention to review §3.73,
as proposed to be repealed, in accordance with Tex. Gov. Code §2001.39
(
as amended by Acts 1999, 76th Leg., ch. 1499 §1.11(a)
).
The Commission received no comments on the proposed review and repeal of §3.73.
The Commission adopts the repeal pursuant to Texas Transportation
Code, §721.003(a)(8), which permits the Railroad Commission by rule to
exempt itself from the vehicle identification and marking requirements imposed
under Texas Transportation Code, §721.002.
Texas Transportation Code, §§721.002 and 721.003, are affected
by the repeal.
Issued in Austin, Texas, on December 20, 2001.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on December 20, 2001.
TRD-200108174
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: November 9, 2001
For further information, please call: (512) 463-7008
Subchapter A. CONTRACTS AND PURCHASES
The Railroad Commission of Texas adopts the repeal of §20.1,
relating to Protest/Dispute Resolution Procedures, without changes to the
proposal published in the November 9, 2001, issue of the
Texas Register
(26 TexReg 8952), and adopts new §20.1, relating
to Procedures for Filing and Resolving Protests of a Contract Solicitation
or Award, and new §20.10, concerning Bid Opening and Tabulation, without
changes to the proposal published in the November 9, 2001, issue of the
New §20.1 will instruct prospective bidders, offerors, or contractors
about the procedures for filing a protest regarding a Commission procurement.
The rule clearly articulates the information that must be included in a protest,
the procedures for pursuing a protest, the standards by which a protest will
be evaluated, and remedies available for violations of statutes or rules in
the procurement process. Additionally, the rule includes appeal procedures
in the event that the protestant is not satisfied with the Commission's initial
determination.
New §20.1 establishes three levels of consideration of a protest concerning
claimed violations of statutes or rules in the procurement process. At the
first level, the director of finance ("the director") receives protests, gathers
information, and makes a determination. At the second level, the director
of finance and administration ("the DFA") receives appeals of determinations
made by the director of finance. At the third level, the Commission entertains
appeals of determinations made by the director of finance and administration.
For any determination which would result in a contract being declared void
or rescinded, the Commission makes the final decision.
New §20.1(a) contains definitions of key terms used in the rule. New §20.1(b)
contains general provisions that govern the filing of a protest, appeal, or
appeal to the Commission, including a delegation of authority to the director
and the DFA to resolve complaints and appeals. In the event the director receives
a timely, proper protest, the director may not proceed further with the solicitation
or with the award of the contract in question unless the director makes a
written determination that the award of the contract, without delay, is necessary
to protect substantial interests of the state. Any protest determination by
the director or appeal determination by the DFA that results in a declaration
that a contract should be void or rescinded and that is not appealed must
be forwarded to the next level as if it were an appeal. A protest or appeal
determination that does not declare a contract void or rescinded and that
is not timely appealed is considered to be the final administrative action
of the Commission.
New §20.1(c) states the proper ground for filing a protest, an appeal,
or an appeal to the Commission, and the basis on which the director, the DFA,
and the Commission may decline to consider and may dismiss a matter. The absence
of an award of a contract to a protestant, an appellant, or a person who appeals
to the Commission is not a proper ground for protest or appeal, unless that
protestant, appellant, or person makes a specific factual allegation that
the failure to award a contract to that protestant, appellant, or person was
the result of a violation of statutes or rules. Unless a protestant, appellant,
or person who appeals to the Commission demonstrates good cause for delay
or unless the director, the DFA, or the Commission determines that a protest
or appeal raises issues significant to procurement practices or procedures,
the director, the DFA, and the Commission shall not consider a protest, an
appeal, or an appeal to the Commission that is not timely filed. Finally,
the director, the DFA, or the Commission may dismiss a protest or an appeal
that fails to state a proper ground; that is untimely; or that is incomplete
when filed.
New §20.1(d) prescribes the contents of protest and establishes the
deadline for filing a protest, which is generally no later than the tenth
day after the protestant knows or should have known of the occurrence of the
action that is protested; new subsection (e) sets forth the director's obligations
in the event of receiving a protest, one of which is to notify all other vendors
for the procurement that is the subject of the protest and invite them to
submit comments or request to participate in the protest inquiry. If a protest
is not withdrawn by the protestant, the director must issue a written determination
on the protest by letter and notify the protestant and all interested parties.
If the director determines that no violation of rules or statutes has occurred,
regardless of whether a contract has been awarded, the director must so state
and give the reasons for the determination. If no contract has been awarded,
the director may proceed with the award of a contract. If the director determines
that a violation of the rules or statutes has occurred in a case in which
no contract has been awarded, the director must so state and give both the
reasons for the determination and the appropriate remedial action and may,
at the director's discretion, proceed with the award of a contract. If the
director determines that a violation of the rules or statutes has occurred
in a case in which a contract has been awarded, the director must so state
and shall set forth the reasons for the determination and the appropriate
remedial action, which may include declaring the contract void or rescinded.
Any protest determination that declares a contract void or rescinded that
is not appealed by an appellant must be forwarded to the DFA to be reviewed
as if it were an appeal.
New §20.1(f) sets forth the procedure on appeal of a director's determination
to the DFA, and prescribes the contents of an appeal and the deadline for
filing it. The DFA's obligations on appeal, set forth in new subsection (g),
include notifying all other interested parties in the protest inquiry and
determination that is the subject of the appeal, inviting their participation
in the appeal, and setting a deadline by which they must respond. The DFA
may request that the General Counsel review and make a recommendation on the
matter. If an appeal is not withdrawn by the appellant, the DFA must issue
a written determination on the appeal by letter. If the DFA determines that
the director's determination was substantially correct, the DFA must so state
and give the reasons for the determination. If the DFA determines that the
director's determination was substantially incorrect, the DFA must so state
and provide the reasons for the determination and the appropriate remedial
action. Any appeal determination that results in a contract being declared
void or rescinded and that is not appealed must be forwarded to the Commission
to be reviewed.
New §20.1(h) describes the procedures applicable when a DFA's appeal
determination is appealed to the Commission. The appeal is filed with the
General Counsel, who schedules the matter for consideration at an open meeting
of the Commission, notifies the parties, and sets a deadline by which parties
must file any additional comments or request to be heard in oral argument
before the Commission at the scheduled open meeting. The Commission's determination
of the appeal must be by written order.
Finally, new §20.1(i) provides that, in the event the Commission receive
a protest, the Commission will retain documents collected as part of a solicitation,
evaluation, and/or award of a contract for a period of four years from the
date of the initial procurement action. In addition, the Commission will also
retain the protest file, the appeal file, and any documents or Commission
orders pertaining to a determination made by the Commission.
New §20.10 will instruct prospective bidders, offerors, or contractors
in the bid opening and tabulation process used by the Commission. The rule
adopts by reference the practices of the Texas Building and Procurement Commission
(formerly the General Services Commission) found in 1 Texas Administrative
Code §113.5(b), relating to Bid Submission, Bid Opening and Tabulation,
as required by Texas Government Code, §2156.005(d). These practices provide
that all bid openings shall be open to the public; bid opening dates may be
changed and bid openings rescheduled if bidders are properly notified in advance
of the new opening date; if a bid opening is canceled, all bids which are
being held for opening will be returned to the bidders; and all bid tabulation
files are available for public inspection. Bid tabulations may be reviewed
by any interested person during regular working hours at the offices of the
Commission. Employees of the Commission are not required to give bid tabulation
information by telephone.
Also, in a separate, concurrent action, the Commission adopted the review
of current §20.1, required under Texas Government Code, §2001.039
(
as added by Acts 1999, 76th Leg., ch. 1499, §1.11(a)
).
16 TAC §20.1
The Commission adopts the repeal of §20.1 pursuant to
Texas Government Code, §2155.076, which requires agencies to develop
and adopt protest procedures for resolving vendor protests relating to purchasing
issues that are consistent with the rules of the Texas Building and Procurement
Commission.
Texas Government Code, §2155.076, is affected by the repeal.
Issued in Austin, Texas, on December 20, 2001.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on December 20, 2001.
TRD-200108171
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: November 9, 2001
For further information, please call: (512) 463-7008
16 TAC §20.1, §20.10
The Commission adopts new §20.1 pursuant to Texas Government
Code, §2155.076, which requires agencies to develop and adopt protest
procedures for resolving vendor protests relating to purchasing issues that
are consistent with the rules of the Texas Building and Procurement Commission;
and new §20.10 pursuant to Texas Government Code, §2156.005, which
requires state agencies making purchases to adopt the Texas Building and Procurement
Commission's rules related to bid opening and tabulation.
Texas Government Code, §§2155.076 and 2156.005, are affected
by the new rules.
Issued in Austin, Texas, on December 20, 2001.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed
with the Office of the Secretary of State on December 20, 2001.
TRD-200108172
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: November 9, 2001
For further information, please call: (512) 463-7008
16 TAC §20.401, §20.405
The Railroad Commission of Texas adopts new §20.401,
relating to Agency Vehicles, and §20.405, relating to Inscriptions on
Railroad Commission of Texas Vehicles, without changes to the proposal published
in the November 9, 2001, issue of the
Texas Register
(26 TexReg 8957). The new rules will be in new subchapter E to be
titled Vehicle Management.
The Commission adopts new §20.401 pursuant to Texas Government Code, §2171.1045,
which requires each state agency to adopt rules consistent with the management
plan adopted under Texas Government Code, §2171.104, relating to the
assignment and use of the agency's vehicles. The management plan was adopted
by the State Council on Competitive Government on October 11, 2000. The legislature
stated, in Senate Bill 1, Article 9, Section 9.13, 77th Legislature (2001),
its intent that all state agencies adopt rules or policies to implement the
State Vehicle Fleet Management Plan, issued by the Office of Vehicle Fleet
Management of the General Services Commission (now the Texas Building and
Procurement Commission).
The State Vehicle Fleet Management Plan sets forth management provisions
regarding: (1) opportunities for consolidating and privatizing the operation
and management of vehicle fleets in areas where there is a concentration of
state agencies, including the Capitol Complex and the Health and Human Services
Complex in Austin; (2) the number and type of vehicles owned by each agency
and the purpose each vehicle serves; (3) procedures to increase vehicle use
and improve the efficiency of the state vehicle fleet; (4) procedures to reduce
the cost of maintaining state vehicles; (5) the sale of excess state vehicles;
and (6) lower- cost alternatives to using state-owned vehicles, including
using rental cars and reimbursing employees for using personal vehicles. The
plan may be viewed on the web site of the General Services Commission (now
known as the Texas Building and Procurement Commission) at www.gsc.state.tx.us/fleet.
The Railroad Commission adopted its vehicle management plan on February 22,
2001.
The Commission adopts new §20.405 in order to move the rule text from §3.73
(commonly referred to as Statewide Rule 75) into Chapter 20, Subchapter D,
relating to Vehicle Management. The repeal of §3.73, and the concurrent
rule review, were proposed in separate, concurrent rulemakings. Other than
the change in chapter and rule number and correction of a statutory citation,
there are no substantive changes to the current rule language. The rule declares
that Railroad Commission vehicles are exempt from the identification requirements
imposed on agencies under Texas Transportation Code, §721.002, as permitted
by Texas Transportation Code, §721.003(a)(8).
The Commission received no comments on the proposed new rules.
The Commission adopts new §20.401 under Texas Government
Code, §2171.1045, which requires the Commission to adopt rules consistent
with the management plan adopted under Texas Government Code, §2171.104,
relating to the assignment and use of the agency's vehicles. The Commission
adopts new §20.405 under Texas Transportation Code, §721.003, which
permits the Commission by rule to exempt its vehicles from the identification
requirement imposed on agencies under Texas Transportation Code, §721.002.
Texas Government Code, §§2171.104 and 2171.1045, and Texas Transportation
Code, §§721.002 and 721.003, are affected by the new sections.
Issued in Austin, Texas, on December 20, 2001.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on December 20, 2001.
TRD-200108175
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: January 9, 2002
Proposal publication date: November 9, 2001
For further information, please call: (512) 463-7008
Chapter 3.
OIL AND GAS DIVISION
Chapter 20.
ADMINISTRATION
Subchapter E. VEHICLE MANAGEMENT
Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS