Current through Register Vol. 35, No. 18, September 24, 2024
A.
Statewide natural gas capture
requirements. Commencing April 1, 2022, the operator shall reduce the
annual volume of vented and flared natural gas in order to capture no less than
ninety-eight percent of the natural gas produced from its wells in each of two
reporting areas, one north and one south of the Township 10 North line, by
December 31, 2026. The division shall calculate and publish on the division's
website each operator's baseline natural gas capture rate based on the
operator's fourth quarter 2021 and first quarter 2022 quarterly reports as per
Paragraph (2) of Subsection G of 19.15.27.8 NMAC. In each calendar year between
January 1, 2022 and December 31, 2026, the operator shall increase its annual
percentage of natural gas captured in each reporting area in which it operates
based on the following formula: (baseline loss rate minus two percent) divided
by five, except that for 2022 only, an operator's percentage of natural gas
captured shall not be less than seventy-five percent of the annual gas capture
percentage increase (2022 baseline loss rate minus two percent divided by five
times 0.75), and the balance shall be captured in 2023.
(1) The following table provides examples of
the formula based on a range of baseline natural gas capture rates.
| Baseline Natural Gas Capture Rate | Minimum
Required Annual Natural Gas Capture Percentage Increase |
| 90-98% | 0-1.6% |
| 80-89% | >1.6-3.6% |
| 70-79% | >3.6-5.6% |
| 0-69% | >5.6-19.6% |
(2)
If the operator's baseline capture rate is less than sixty percent, the
operator shall submit by the specified date to the division for approval a plan
to meet the minimum required annual capture percentage increase.
(3) An operator's acquisition or saleof one
or more wells from another operator shall not affect its annual natural gas
capture requirements. No later 60 days following the acquisition or sale, the
operator may file a written request to the division requesting to modify its
gas capture percentage requirements for good cause based on its acquisition or
sale. The division may approve, approve with conditions, or deny the request in
its sole discretion.
(4) No later
than March 30 following the reporting year, an operator that has not met its
annual natural gas capture requirement for the previous year shall submit to
the division a compliance plan demonstrating its ability to comply with its
annual gas capture requirement for the current year. If the division
determines, after a reasonable opportunity to meet with the operator, that the
compliance plan does not demonstrate the operator's ability to comply with its
annual gas capture requirement for the current year the operator's approved
APDs for wells that have not been spud shall be suspended pending a division
hearing to be held no later than 30 days after the determination. Nothing in
this subparagraph shall prevent the division from taking any other action
authorized by law for the operator's failure to comply with its annual gas
capture requirement, including shutting in wells and assessing civil penalties.
B.
Accounting. No later than February 28 of each year beginning in
2023, the operator shall submit a report certifying compliance with its
statewide gas capture requirements. The operator shall determine compliance
with its statewide gas capture requirements by deducting any ALARM credits
approved pursuant to this subsection from the aggregated volume of lost gas
calculated for each month during the preceding year pursuant to Subparagraph
(a) of Paragraph (3) of Subsection G of 19.15.27.8 NMAC, deducting that
aggregated volume of lost gas from the aggregated volume of natural gas
produced for each month during the preceding year, and dividing that volume by
the aggregated volume of natural gas produced for each month during the
preceding year.
(1) An operator that used a
division-approved ALARM technology to monitor for leaks and releases may obtain
a credit against the volume of lost natural gas if it discovered the leak or
release using the ALARM technology and the operator:
(a) isolated the leak or release within 48
hours following field verification;
(b) repaired the leak or release within 15
days following field verification or another date approved by the
division;
(c) timely notified the
division by filing a form C-129 or form C-141; and
(d) used ALARM monitoring technology as a
routine and on-going aspect of its waste-reduction practices.
(i) For discrete waste-reduction practices
such as aerial methane monitoring, the operator must use the technology at
least twice per year; and
(ii) for
waste-reduction practices such as automated emissions monitoring systems that
operate routinely or continuously, the division will determine the required
frequency of use.
(e) The
division shall publish a list of division-approved ALARM technologies on the
division's website.
(2)
An operator may file an application with the division for a credit against its
volume of lost natural gas that identifies:
(a) the ALARM technology used to discover the
leak or release;
(b) the dates on
which the leak or release was discovered, field-verified, isolated and
repaired;
(c) the method used to
measure or estimate the volume of natural gas leaked or released which method
shall be consistent with Subsection F of 19.15.27.8 NMAC;
(d) a description and the date of each action
taken to isolate and repair the leak or release;
(e) visual documentation or other
verification of discovery, isolation and repair of the leak or
release;
(f) a certification that
the operator did not know or have reason to know of the leak or release before
discovery using ALARM technology; and
(g) a description of how the operator used
ALARM technology as a routine and on-going aspect of its waste-reduction
practices.
(3) For each
leak or release reported by an operator that meets the requirements of
Paragraphs (3) and (4) of Subsection B of 29.15.28.10 NMAC, the division, in
its sole discretion, may approve a credit that the operator can apply against
its reported volume of lost natural gas as follows:
(a) a credit of forty percent of the volume
of natural gas discovered and isolated within 48 hours of discovery and timely
repaired;
(b) an additional credit
of twenty percent if the operator used ALARM technology no less than once per
calendar quarter as a routine and on-going aspect of its waste-reduction
practices.
(4) A
division-approved ALARM credit shall:
(a) be
used only by the operator who submitted the application pursuant to Paragraph
(4) of Subsection B of 29.15.27.10 NMAC;
(b) not be transferred to or used by another
operator, including a parent, subsidiary, related entity, or person acquiring
the well;
(c) be used only once;
and
(d) expire 24 months after
division approval.
(5)
The division will publish a list of approved ALARM technology.
C.
Third-party
verification. The division may request that an operator retain a third
party to verify any data or information collected or reported pursuant to this
Part, make recommendations to correct or improve the collection and reporting
of data and information, submit a report of the verification and
recommendations to the division by the specified date, and implement the
recommendations in the manner approved by the division. If the division and the
operator cannot reach agreement on the division's request, the operator may
file an application for hearing before the division. The operator, at its own
expense, shall retain a third party approved by the division to conduct the
activities agreed to by the division and the operator or ordered by the
division following a hearing.
D.
Natural gas management plan.
(1)
After May 25, 2021, the operator shall file a natural gas management plan with
each APD for a new or recompleted well. The operator may file a single natural
gas management plan for multiple wells drilled or recompleted from a single
well pad or that will be connected to a central delivery point. The natural gas
management plan shall describe the actions that the operator will take at each
proposed well to meet its statewide natural gas capture requirements and to
comply with the requirements of Subsections A through F of 19.15.27.8 NMAC,
including for each well:
(a) the operator's
name and OGRID number;
(b) the
name, API number, location and footage;
(c) the anticipated dates of drilling,
completion and first production;
(d) a description of operational best
practices that will be used to minimize venting during active and planned
maintenance; and
(e) the
anticipated volumes of liquids and gas production and a description of how
separation equipment will be sized to optimize gas capture.
(2) Beginning April 1,
2022, an operator that, at the time it submits an APD for a new or recompleted
well is, cumulatively for the year, not in compliance with its baseline natural
gas capture rate for the applicable reporting area if the APD is submitted on
or after April 1, 2022 or its natural gas capture requirement for the previous
year if the APD is submitted in 2023 or after shall also include the following
information in the natural gas management plan:
(a) the anticipated volume of produced
natural gas in units of MCFD for the first year of production;
(b) the existing natural gas gathering system
the operator has contracted or anticipates contracting with to gather the
natural gas, including:
(i) the name of the
natural gas gathering system operator;
(ii) the name and location of the natural gas
gathering system;
(iii) a map of
the well location and the anticipated pipeline route connecting the production
operations to the existing or planned interconnect of the natural gas gathering
system.; and
(iv) the maximum daily
capacity of the segment or portion of the natural gas gathering system to which
the well will be connected; and
(c) the operator's plans for connecting the
well to the natural gas gathering system, including:
(i) the anticipated date on which the natural
gas gathering system will be available to gather the natural gas produced from
the well;
(ii) whether the natural
gas gathering system has or will have capacity to gather the anticipated
natural gas production volume from the well prior to the date of first
production; and
(iii) whether the
operator anticipates the operator's existing well(s) connected to the same
segment or portion of the natural gas gathering system, referenced in Item (iv)
of Subparagraph (b) of Paragraph (2) of Subsection D or 19.15.27.9 NMAC will
continue to be able to meet anticipated increases in line pressure caused be
the well and the operator's plan to manage production in response to the
increased line pressure.
(3) The operator may assert confidentiality
for information specified in Paragraph (2) of Subsection D of 19.15.27.9 NMAC
pursuant to Section
71-2-8
NMSA 1978.
(4) The operator shall
certify that it has determined based on the available information at the time
of submitting the natural gas management plan either:
(a) it will be able to connect the well to a
natural gas gathering system in the general area with sufficient capacity to
transport one hundred percent of the volume of natural gas the operator
anticipates the well will produce commencing on the date of first production,
taking into account the current and anticipated volumes of produced natural gas
from other wells connected to the pipeline gathering system; or
(b) it will not be able to connect to a
natural gas gathering system in the general area with sufficient capacity to
transport one hundred percent of the volume of natural gas the operator
anticipates the well will produce commencing on the date of first production,
taking into account the current and anticipated volumes of produced natural gas
from other wells connected to the pipeline gathering
system.
(5) If the
operator determines it will not be able to connect a natural gas gathering
system in the general area with sufficient capacity to transport one hundred
percent of the anticipated volume of natural gas produced on the date of first
production from the well, the operator shall either shut-in the well until the
operator submits the certification required by Paragraph (4) of Subsection D of
19.15.27.9 NMAC or submit a venting and flaring plan to the division that
evaluates and selects one or more of the potential alternative beneficial uses
for the natural gas until a natural gas gathering system is available,
including:
(a) power generation on
lease;
(b) power generation for
grid;
(c) compression on
lease;
(d) liquids removal on
lease;
(e) reinjection for
underground storage;
(f)
reinjection for temporary storage;
(g) reinjection for enhanced oil
recovery;
(h) fuel cell production;
and
(i) other alternative
beneficial uses approved by the division.
(6) If, at any time after the operator
submits the natural gas management plan and before the well is spud:
(a) the operator becomes aware that the
natural gas gathering system it planned to connect the well to has become
unavailable or will not have capacity to transport one hundred percent of the
production from the well, no later than 20 days after becoming aware of such
information, the operator shall submit for the division's approval a new or
revised venting and flaring plan containing the information specified in
Paragraph (5) of Subsection D of 19.15.27.9 NMAC; and
(b) the operator becomes aware that it has,
cumulatively for the year, become out of compliance with its baseline natural
gas capture rate or natural gas capture requirement, no later than 20 days
after becoming aware of such information, the operator shall submit for the
division's approval a new or revised natural gas management plan for each well
it plans to spud during the next 90 days containing the information specified
in Paragraph (2) of Subsection D of 19.15.27.9 NMAC, and shall file an update
for each plan until the operator is back in compliance with its baseline
natural gas capture rate or natural gas capture requirement.
(7) The division may deny the APD
or conditionally approve the APD if the operator does not make a certification,
fails to submit an adequate venting and flaring plan, which includes
alternative beneficial uses for the anticipated volume of natural gas produced,
or if the division determines that the operator will not have adequate natural
gas takeaway capacity at the time a well will be spud.
