of this subpart. For meters/piping, use one meters/piping per well-pad.
* * * * *
    (6) * * *
    (i) Below grade metering-regulating stations (including below grade
T-D transfer stations); distribution mains; and distribution services,
shall use the appropriate default population emission factors listed in
Table W-7 of this subpart.
    (ii) Emissions from all above grade metering-regulating stations
(including above grade TD transfer stations) shall be calculated by
applying the emission factor calculated in Equation W-32 and the total
count of meter/regulator runs at all above grade metering-regulating
stations (inclusive of TD transfer stations) to Equation W-31. The
facility wide emission factor in Equation W-32 will be calculated by
using the total volumetric GHG emissions at standard conditions for all
equipment leak sources calculated in paragraph (q)(8) of this section
and the count of meter/regulator runs located at above grade
transmission-distribution transfer stations.
[GRAPHIC] [TIFF OMITTED] TP09SE11.014

Where:
EFi = Facility emission factor for a meter/regulator run
at above grade metering-regulating for GHGi in cubic feet
per meter/regulator run per hour.
Es,i = Annual volumetric GHG i emissions, CO2
or CH4 at standard condition from all equipment leak
sources at all above grade TD transfer stations, from paragraph (q)
of this section.
Count = Total number of meter/regulator runs at all TD transfer
stations.
8760 = Conversion to hourly emissions
* * * * *

    (t) Volumetric emissions. Calculate volumetric emissions at
standard conditions as specified in paragraphs (t)(1) or (2) of this
section, with actual pressure and temperature determined by engineering
estimates based on best available data unless otherwise specified.
    (1) Calculate natural gas volumetric emissions at standard
conditions using

actual natural gas emission temperature and pressure, and Equation W-33
of this section.
* * * * *
    (2) Calculate GHG volumetric emissions at standard conditions using
actual GHG emissions temperature and pressure, and Equation W-34 of
this section.
* * * * *
    (u) GHG volumetric emissions. Calculate GHG volumetric emissions at
standard conditions as specified in paragraphs (u)(1) and (2) of this
section, with mole fraction of GHGs in the natural gas determined by
engineering estimate based on best available data unless otherwise
specified.
* * * * *
    (2) For Equation W-35 of this section, the mole fraction, Mi, shall
be the annual average mole fraction for each sub-basin category or
facility, as specified in paragraphs (u)(2)(i) through (vii) of this
section.
    (i) GHG mole fraction in produced natural gas for onshore petroleum
and natural gas production facilities. If you have a continuous gas
composition analyzer for produced natural gas, you must use an annual
average of these values for determining the mole fraction. If you do
not have a continuous gas composition analyzer, then you must use an
annual average gas composition based on available analyses in each of
the sub-basin categories.
    (ii) GHG mole fraction in feed natural gas for all emissions
sources upstream of the de-methanizer or dew point control and GHG mole
fraction in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole percent in feed natural
gas liquid for all streams. If you have a continuous gas composition
analyzer on feed natural gas, you must use these values for determining
the mole fraction. If you do not have a continuous gas composition
analyzer, then annual samples must be taken according to methods set
forth in Sec.  98.234(b).
    (iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for onshore natural gas transmission
compression facilities. You may use a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas.
    (iv) GHG mole fraction in natural gas stored in underground natural
gas storage facilities. You may use a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas.
    (v) GHG mole fraction in natural gas stored in LNG storage
facilities. You may use a default 95 percent methane and 1 percent
carbon dioxide fraction for GHG mole fraction in natural gas.
    (vi) GHG mole fraction in natural gas stored in LNG import and
export facilities. For export facilities that receive gas from
transmission pipelines, you may use a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas.
    (vii) GHG mole fraction in local distribution pipeline natural gas
that passes through the facility for natural gas distribution
facilities. You may use a default 95 percent methane and 1 percent
carbon dioxide fraction for GHG mole fraction in natural gas.
    (v) GHG mass emissions. Calculate GHG mass emissions in carbon
dioxide equivalent at standard conditions by converting the GHG
volumetric emissions at standard conditions into mass emissions using
Equation W-36 of this section.
* * * * *

Masss,i = GHG i (either CH4, CO2,
or N2O) mass emissions at standard conditions in metric
tons CO2e.
Es,i = GHG i (either CH4, CO2, or
N2O) volumetric emissions at standard conditions, in
cubic feet.
[rho]i = Density of GHG i. Use 0.0520 kg/ft\3\ for
CO2 and N2O, and 0.0190 kg/ft\3\ for
CH4 at 68 [deg]F and 14.7 psia or 0.0530 kg/ft\3\ for
CO2 and N2O, and 0.0193 kg/ft\3\ for
CH4 at 60 [deg]F and 14.7 psia.
* * * * *

    (z) Onshore petroleum and natural gas production and natural gas
distribution combustion emissions. Calculate CO2,
CH4, and N2O combustion-related emissions from
stationary or portable equipment, except as specified in paragraph
(z)(3) of this section, as follows:
    (1) If a fuel combusted in the stationary or portable equipment is
listed in Table C-1 of subpart C of this part, or is a blend containing
one or more fuels listed in Table C-1, calculate emissions according to
(z)(1)(i). If the fuel is natural gas and is of pipeline quality
specification and has a minimum high heat value of 950 Btu per standard
cubic foot, use the calculation methodology described in (z)(1)(i) and
you may use the emission factor provided for natural gas as listed in
Table C-1. If the fuel is natural gas, and is not pipeline quality or
has a high heat value of less than 950 But per standard cubic feet,
calculate emissions according to (z)(2). If the fuel is field gas,
process vent gas, or a blend containing field gas or process vent gas,
calculate emissions according to (z)(2).
    (i) For fuels listed in Table C-1 or a blend containing one more
fuels listed in Table C-1, calculate CO2, CH4,
and N2O emissions according to any Tier listed in subpart C
of this part. You must follow all applicable calculation requirements
for that tier listed in 98.33, any monitoring or QA/QC requirements
listed for that tier in 98.34, any missing data procedures specified in
98.35, and any recordkeeping requirements specified in 98.37.
    (ii) Emissions from fuel combusted in stationary or portable
equipment at onshore natural gas and petroleum production facilities
and at natural gas distribution facilities will be reported according
to the requirements specified in 98.236(c)(19) and not according to the
reporting requirements specified in subpart C of this part.
    (2) For fuel combustion units that combust field gas, process vent
gas, a blend containing field gas or process vent gas, or natural gas
that is not of pipeline quality or that has a high heat value of less
than 950 Btu per standard cubic feet, calculate combustion emissions as
follows:
    (i) You may use company records to determine the volume of fuel
combusted in the unit during the reporting year.
    (ii) If you have a continuous gas composition analyzer on fuel to
the combustion unit, you must use these compositions for determining
the concentration of gas hydrocarbon constituent in the flow of gas to
the unit. If you do not have a continuous gas composition analyzer on
gas to the combustion unit, you must use the appropriate gas
compositions for each stream of hydrocarbons going to the combustion
unit as specified in paragraph (u)(2)(i) of this section.
    15. Section 98.234 is amended by:
    a. Revising paragraphs (a)(1), (a)(2), and (a)(5).
    b. Removing and reserving paragraph (a)(4).
    c. Revising paragraph (c) introductory text and paragraph (d)(3).

Sec.  98.234  Monitoring and QA/QC requirements.

    (a) * * *
    (1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection in accordance with 40 CFR part
60, subpart A, Sec.  60.18 of the Alternative work practice for
monitoring equipment leaks, Sec.  60.18(i)(1)(i); Sec.  60.18(i)(2)(i)
except that the monitoring frequency shall be annual using the
detection

sensitivity level of 60 grams per hour as stated in 40 CFR part 60,
subpart A, Table 1: Detection Sensitivity Levels; Sec.  60.18(i)(2)(ii)
and (iii) except the gas chosen shall be methane, and Sec.
60.18(i)(2)(iv) and (v); Sec.  60.18(i)(3); Sec.  60.18(i)(4)(i) and
(v); including the requirements for daily instrument checks and
distances, and excluding requirements for video records. Any emissions
detected by the optical gas imaging instrument is a leak unless
screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in
which case 10,000 ppm or greater is designated a leak. In addition, you
must operate the optical gas imaging instrument to image the source
types required by this subpart in accordance with the instrument
manufacturer's operating parameters. An optical gas imaging instrument
must be used for all source types that are inaccessible and cannot be
monitored without elevating the monitoring personnel more than 2 meters
above a support surface.
    (2) Method 21. Use the equipment leak detection methods in 40 CFR
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an
instrument reading of 10,000 ppm or greater is measured, a leak is
detected. Inaccessible emissions sources, as defined in 40 CFR part 60,
are not exempt from this subpart. Owners or operators must use
alternative leak detection devices as described in paragraph (a)(1) or
(a)(2) of this section to monitor inaccessible equipment leaks or
vented emissions.
* * * * *
    (5) Acoustic leak detection device. Use the acoustic leak detection
device to detect through-valve leakage. When using the acoustic leak
detection device to quantify the through-valve leakage, you must use
the instrument manufacturer's calculation methods to quantify the
through-valve leak. When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected.
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer's operating parameters. Acoustic
stethoscope type devices designed to detect through valve leakage when
put in contact with the valve body and that provide an audible leak
signal but do not calculate a leak rate can be used to identify non-
leakers with subsequent measurement required to calculate the rate if
through-valve leakage is identified. Leaks are reported if a leak rate
of 3.1 scf per hour or greater is measured.
* * * * *
    (c) Use calibrated bags (also known as vent bags) only where the
emissions are at near-atmospheric pressures and below the maximum
temperature specified by the vent bag manufacturer such that the bag is
safe to handle. The bag must be of sufficient size that the entire
emissions volume can be encompassed for measurement.
* * * * *
    (d) * * *
    (3) Estimate natural gas volumetric emissions at standard
conditions using calculations in Sec.  98.233(t). Estimate
CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions using the calculations in Sec.
98.233(u) and (v).
    16. Section 98.236 is amended by:
    a. Revising paragraphs (a) introductory text and (a)(8).
    b. Revising paragraph (b).
    c. Revising paragraphs (c) introductory text, (c)(1)(iv),
(c)(2)(ii), and (c)(3)(ii) through (c)(3)(v); and adding paragraphs
(c)(3)(vi) and (vii).
    d. Revising paragraphs (c)(4)(i)(H) and (C)(4)(i)(J); and adding
paragraphs (c)(4)(i)(K) and (c)(4)(i)(L).
    e. Revising paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(C); and adding
paragraph (c)(4)(ii)(D).
    f. Revising paragraph (c)(4)(iii)(B).
    g. Revising paragraphs (c)(5) introductory text, (c)(5)(iii), and
(c)(5)(vi); and adding paragraph (c)(5)(vii).
    h. Revising paragraphs (c)(6) introductory text, (c)(6)(i)
introductory text, (c)(6)(i)(B), (c)(6)(i)(D), (c)(6)(i)(G), and
(c)(6)(i)(H); and adding paragraph (c)(6)(ii)(I).
    i. Revising paragraphs (c)(6)(ii)(B) and (c)(6)(ii)(D); and adding
paragraph (c)(6)(ii)(E).
    j. Revising paragraphs (c)(7)(i) and (c)(7)(ii); and adding
paragraph (c)(7)(iii).
    k. Revising paragraphs (c)(8)(i) introductory text and
(c)(8)(i)(J); and adding paragraphs (c)(8)(i)(K) through (c)(8)(i)(M).
    l. Revising paragraphs (c)(8)(ii) introductory text, (c)(8)(ii)(D),
and (c)(8)(ii)(G); and adding paragraphs (c)(8)(ii)(H) and
(c)(8)(ii)(I).
    m. Revising paragraphs (c)(8)(iii) introductory text and
(c)(8)(iii)(F); and adding paragraphs (c)(8)(iii)(G) and
(c)(8)(iii)(H).
    n. Adding paragraph (c)(8)(iv)(B).
    o. Revising paragraphs (c)(9)(i) and (c)(9)(ii); and adding
paragraph (c)(9)(iii).
    p. Revising paragraphs (c)(10) introductory text and (c)(10)(iv);
and adding paragraph (c)(10)(v).
    q. Revising paragraph (c)(11) introductory text and (c)(11)(iii);
and adding paragraph (c)(11)(iv).
    r. Revising paragraph (c)(12)(vi) and adding paragraphs
(c)(12)(vii) through (c)(12)(xi).
    s. Revising paragraphs (c)(15)(i)(B) and (c)(15)(i)(C).
    t. Revising paragraphs (c)(15)(ii)(A) through (c)(15)(ii)(C).
    u. Revising paragraphs (c)(16)(i) through (c)(16)(iv), (c)(16)(vi),
and (c)(16)(xv).
    v. Removing and reserving paragraph (c)(16)(v).
    w. Adding paragraphs (c)(16)(xvi) through (c)(16)(xx).
    x. Revising paragraph (c)(17)(v) and adding paragraph (c)(17)(vi).
    y. Revising paragraph (c)(18) introductory text and paragraph
(c)(18)(iii).
    z. Revising paragraph (c)(19)(iii) and (c)(19)(vi).
    aa. Adding paragraph (e).
    The revisions read as follows:

Sec.  98.236  Data Reporting Requirements.

* * * * *
    (a) Report annual emissions separately for each of the industry
segments listed in paragraphs (a)(1) through (8) of this section.
* * * * *
    (8) Natural gas distribution.
    (b) For offshore petroleum and natural gas production, report
emissions of CH4, CO2, and N2O as
applicable to the source type (in metric tons CO2e per year
at standard conditions) individually for all the emissions source types
listed in the most recent BOEMRE study.
    (c) Report the information listed in this paragraph for each
applicable source type. If a facility operates under more than one
industry segment, each piece of equipment should be reported under its
respective majority use segment. When a source type listed under this
paragraph routes gas to flare, separately report the emissions that
were vented directly to the atmosphere without flaring, and the
emissions that resulted from flaring the gas. Both the vented and
flared emissions will be reported under the respective source type and
not under the flare source type.
    (1) * * *
    (iv) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, for each of the following pieces of equipment: high bleed
pneumatic devices; intermittent bleed pneumatic devices; low bleed
pneumatic devices.

    (2) * * *
    (ii) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, for all natural gas driven pneumatic pumps combined.
    (3) * * *
    (ii) For Calculation Methodology 1 and Calculation Methodology 2 of
Sec.  98.233(d), annual average fraction of CO2 content in
the vent from the acid gas removal unit (refer to Sec.  98.233(d)(6)).
    (iii) For Calculation Methodology 3 of Sec.  98.233(d), annual
average volume fraction of CO2 content of natural gas into
and out of the acid gas removal unit (refer to Sec.  98.233(d)(7) and
(d)(8)).
    (iv) Report the annual quantity of CO2, expressed in
metric tons CO2e, that was recovered from the AGR unit and
transferred outside the facility.
    (v) Report annual CO2 emissions for the AGR unit,
expressed in metric tons CO2e.
    (vi) A unique name or ID number for the AGR unit.
    (vii) An indication of which calculation methodology was used for
the AGR.
    (4) * * *
    (i) * * *
    (H) Concentration of CH4 and CO2 in wet
natural gas.
* * * * *
    (J) For each glycol dehydrator, report annual CO2 and
CH4 emissions that resulted from venting gas directly to the
atmosphere, expressed in metric tons CO2e for each gas.
    (K) For each glycol dehydrator, report annual CO2,
CH4, and N2O emissions that resulted from flaring
process gas from the dehydrator, expressed in metric tons
CO2e for each gas.
    (L) A unique name or ID number for the glycol dehydrator.
    (ii) * * *
    (B) Which vent gas controls are used (refer to Sec.  98.233(e)(3)
and (e)(4)).
    (C) Report annual CO2 and CH4 emissions at
the facility level that resulted from venting gas directly to the
atmosphere, expressed in metric tons CO2e for each gas,
combined for all glycol dehydrators with a throughput of less than 0.4
MMscfd.
    (D) Report annual CO2, CH4, and
N2O emissions at the facility level that resulted from the
flaring of process gas, expressed in metric tons CO2e for
each gas, combined for all glycol dehydrators with a throughput of less
than 0.4 MMscfd.
    (iii) * * *
    (B) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, for all absorbent desiccant dehydrators combined.
    (5) For well venting for liquids unloading (refer to Equations W-7,
W-8 and W-9 of Sec.  98.233), report the following by each well tubing
diameter grouping and pressure grouping within each sub-basin category:
* * * * *
    (iii) Cumulative number of unloadings vented to the atmosphere.
* * * * *
    (vi) Report annual CO2 and CH4 emissions,
expressed in metric tons CO2e for each gas, for each tubing
diameter and pressure grouping within each sub-basin category.
    (vii) When using Calculation Methodology 1, casing diameter, depth
and pressure of each well selected to represent emissions in that
tubing size and pressure combination (refer to Equation W-7 of Sec.
98.233).
    (6) For well completions and workovers, report the following for
each sub-basin category:
    (i) For gas well completions and workovers with hydraulic
fracturing by sub-basin and well type (horizontal or vertical)
combination (refer to Equation W-10 of Sec.  98.233):
* * * * *
    (B) Average flow rate of the measured well completion venting in
cubic feet per hour (refer to Equation W-12 of Sec.  98.233).
* * * * *
    (D) Average flow rate of the measured well workover venting in
cubic feet per hour (refer to Equation W-12 of Sec.  98.233).
* * * * *
    (G) Report number of completions and number of workovers employing
reduced emissions completions and engineering estimate based on best
available data of the amount of gas recovered to sales.
    (H) Annual CO2 and CH4 emissions that
resulted from venting gas directly to the atmosphere, expressed in
metric tons CO2e for each gas.
    (I) Annual CO2, CH4, and N2O
emissions that resulted from flares, expressed in metric tons
CO2e for each gas.
* * * * *
    (B) Total count of workovers in calendar year that flare gas or
vent gas to the atmosphere.
* * * * *
    (D) Annual CO2 and CH4 emissions that
resulted from venting gas directly to the atmosphere, expressed in
metric tons CO2e for each gas.
    (E) Annual CO2, CH4, and N2O
emissions that resulted from flares, expressed in metric tons
CO2e for each gas.
    (7) * * *
    (i) Total number of blowdowns per unique volume type in calendar
year.
    (ii) Annual CO2 and CH4 emissions, expressed
in metric tons CO2e for each gas, for each unique volume
type, at each blowdown stack.
    (iii) A unique name or ID number for the blowdown vent stack.
    (8) * * *
    (i) For wellhead gas-liquid separator with oil throughput greater
than or equal to 10 barrels per day, using Calculation Methodology 1
and 2 of Sec.  98.233(j), report the following by sub-basin category,
unless otherwise specified:
* * * * *
    (J) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, for each wellhead gas-liquid separator or
storage tank using Calculation Methodology 1 or 2 of Sec.  98.233(j).
    (K) Annual CO2 and CH4 gas quantities that
were recovered, expressed in metric tons CO2e for each gas,
for each wellhead gas-liquid separator or storage tank using
Calculation Methodology 1 or 2 of Sec.  98.233(j).
    (L) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas, expressed in metric tons
CO2e for each gas, for each wellhead gas-liquid separator or
storage tank using Calculation Methodology 1 or 2 of Sec.  98.233(j).
    (M) A unique name or ID number for each wellhead gas liquid
separator or storage tank.
    (ii) For wells with oil production greater than or equal to 10
barrels per day, using Calculation Methodology 3 and 4 of Sec.
98.233(j), report the following by sub-basin category:
* * * * *
    (D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and
(c)(8)(ii)(C) of this section, in degrees.
* * * * *
    (G) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 3 or 4 of Sec.  98.233(j).
    (H) Annual CO2 and CH4 gas quantities that
were recovered, expressed in metric tons CO2e for each gas,
at the sub-basin level for Calculation Methodology 3 or 4 of Sec.
98.233(j).
    (I) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas, expressed in metric tons
CO2e for each gas, at the sub-basin level for

Calculation Methodology 3 and 4 of Sec.  98.233(j).
    (iii) For wellhead gas-liquid separators and wells with throughput
less than 10 barrels per day, using Calculation Methodology 5 of Sec.
98.233(j) Equation W-15 of Sec.  98.233, report the following:
* * * * *
    (F) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 5 of Sec.  98.233(j).
    (G) Annual CO2 and CH4 gas quantities that
were recovered, expressed in metric tons CO2e for each gas,
at the sub-basin level for Calculation Methodology 5 of Sec.
98.233(j).
    (H) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 5 of Sec.  98.233(j).
    (iv) * * *
    (B) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level for improperly
functioning dump valves.
    (9) * * *
    (i) For each transmission storage tank, report annual
CO2 and CH4 emissions that resulted from venting
gas directly to the atmosphere, expressed in metric tons
CO2e for each gas.
    (ii) For each transmission storage tank, report annual
CO2, CH4, and N2O emissions that
resulted from flaring process gas from the transmission storage tank,
expressed in metric tons CO2e for each gas.
    (iii) A unique name or ID number for the transmission storage tank.
    (10) For well testing venting and flaring (refer to Equation W-17
of Sec.  98.233), report the following:
* * * * *
    (iv) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, emissions from well testing venting.
    (v) Report annual CO2, CH4, and
N2O emissions at the facility level, expressed in metric
tons CO2e for each gas, emissions from well testing flaring.
    (11) For associated natural gas venting and flaring (refer to
Equation W-18 of Sec.  98.233), report the following for each basin:
* * * * *
    (iii) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, emissions from associated natural gas venting.
    (iv) Report annual CO2, CH4, and
N2O emissions at the facility level, expressed in metric
tons CO2e for each gas, emissions from associated natural
gas flaring.
    (12) * * *
    (vi) Report uncombusted CH4 emissions, in metric tons
CO2e (refer to Equation W-19 of Sec.  98.233).
    (vii) Report uncombusted CO2 emissions, in metric tons
CO2e (refer to Equation W-20 of Sec.  98.233).
    (viii) Report combusted CO2 emissions, in metric tons
CO2e (refer to Equation W-21 of Sec.  98.233).
    (ix) Report N2O emissions, in metric tons
CO2e.
    (x) A unique name or ID number for the flare stack.
    (xi) In the case that a CEMS is used to measure CO2
emissions for the flare stack, indicate that a CEMS was used in the
annual report and report the combusted CO2 and uncombusted
CO2 as a combined number.
    (15) * * *
    (i) * * *
    (B) For onshore natural gas processing, range of concentrations of
CH4 and CO2 (refer to Equation W-30 of Sec.
98.233).
    (C) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas (refer to Equation W-30 of Sec.
98.233), by equipment type.
    (ii) * * *
    (A) For source categories Sec.  98.230(a)(4), (a)(5), (a)(6),
(a)(7), and (a)(8), total count for each type of leak source in Tables
W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a
population emission factor, listed by major heading and component type.
    (B) For onshore production (refer to Sec.  98.230 paragraph
(a)(2)), total count for each type of major equipment in Table W-1B and
Table W-1C of this subpart, by sub-basin category.
    (C) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas (refer to Equation W-31 of Sec.
98.233), by equipment type.
    (16) * * *
    (i) Number of above grade T-D transfer stations.
    (ii) Number of below grade T-D transfer stations.
    (iii) Number of above grade metering-regulating stations (this
count will include above grade T-D transfer stations).
    (iv) Number of below grade metering-regulating stations (this count
will include below grade T-D transfer stations).
    (v) [Reserved].
    (vi) Above grade metering-regulating station leak factor (refer to
Equation W-32 of Sec.  98.233).
* * * * *
    (xv) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all above grade T-D transfer
stations combined.
    (xvi) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all below grade T-D transfer
stations combined.
    (xvii) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas, from all above grade
metering-regulating stations (including T-D transfer stations)
combined.
    (xviii) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas, from all below grade
metering-regulating stations (including T-D transfer stations)
combined.
    (xix) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all distribution mains
combined.
    (xx) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all distribution services
combined.
    (17) * * *
    (v) For each EOR pump, report annual CO2 and
CH4 emissions, expressed in metric tons CO2e for
each gas.
    (vi) A unique name or ID for the EOR pump.
    (18) For EOR hydrocarbon liquids dissolved CO2 for each
sub-basin category (refer to Equation W-38 of Sec.  98.233), report the
following:
* * * * *
    (iii) Report annual CO2 emissions at the sub-basin
level, expressed in metric tons CO2e.
    (19) * * *
    (iii) Report annual CO2, CH4, and
N2O emissions from external fuel combustion units with a
rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons
CO2e for each gas, by type of unit.
* * * * *
    (vi) Report annual CO2, CH4, and
N2O emissions from internal combustion units, expressed in
metric tons CO2e for each gas, by type of unit.
* * * * *
    (e) For onshore petroleum and natural gas production, report the
average API gravity, average gas to oil ratio, and average low pressure
separator pressure for each sub-basin category.
    17. Section 98.237 is amended by adding paragraph (e) to read as
follows:

Sec.  98.237  Records that must be retained.

* * * * *
    (e) The records required under Sec.  98.3(g)(2)(i) shall include an
explanation of how company records,

engineering estimation, or best available information are used to
calculate each applicable parameter under this subpart.
    18. Section 98.238 is amended by:
    a. Revising the definitions of ``Facility with respect to natural
gas distribution for purposes of this subpart and subpart A'',
``Facility with respect to onshore petroleum and natural gas production
for purposes of this subpart and for subpart A'', ``Farm Taps'', and
``Transmission pipeline''.
    b. Adding definitions of ``Associated with a single well-pad'',
``Distribution pipeline'', ``Flare'', ``Forced extraction'',
``Horizontal well'', ``Natural gas'', ``Metering-regulating station'',
``Pressure groupings'', ``Sub-basin category'', ``Transmission-
distribution transfer station'', ``Tubing diameter groupings'',
``Tubing systems'', ``Vertical well'', and ``Well testing venting and
flaring''.
    c. Removing the definition of ``Field''.
    The revisions read as follows:

Sec.  98.238  Definitions.

* * * * *
    Associated with a single well-pad means associated with the
hydrocarbon stream as produced from one or more wells located on that
single well-pad. The association ends where the stream from a single
well-pad is combined with streams from one or more additional single
well-pads, where the point of combination is located off that single
well-pad. This does not include storage and condensate tanks that are
located downstream of the point of combination.
* * * * *
    Distribution pipeline means a pipeline that is designated as such
by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49
CFR 192.3.
* * * * *
    Facility with respect to natural gas distribution for purposes of
reporting under this subpart and for the corresponding subpart A
requirements means the collection of all distribution pipelines and
metering-regulating stations that are operated by a Local Distribution
Company (LDC) within a single state that is regulated as a separate
operating company by a public utility commission or that are operated
as an independent municipally-owned distribution system.
    Facility with respect to onshore petroleum and natural gas
production for purposes of reporting under this subpart and for the
corresponding subpart A requirements means all petroleum or natural gas
equipment on a well-pad or associated with a well-pad and
CO2 EOR operations that are under common ownership or common
control including leased, rented, or contracted activities by an
onshore petroleum and natural gas production owner or operator and that
are located in a single hydrocarbon basin as defined in Sec.  98.238.
Where a person or entity owns or operates more than one well in a
basin, then all onshore petroleum and natural gas production equipment
associated with all wells that the person or entity owns or operates in
the basin would be considered one facility.
    Farm Taps are pressure regulation stations that deliver gas
directly from transmission pipelines to generally rural customers. In
some cases a nearby LDC may handle the billing of the gas to the
customer(s).
* * * * *
    Flare, for the purposes of subpart W, means a combustion device,
whether at ground level or elevated, that uses an open or closed flame
to combust waste gases without energy recovery.
* * * * *
    Forced extraction of natural gas liquids means removal of ethane or
higher carbon number hydrocarbons existing in the vapor phase in
natural gas, by removing ethane or heavier hydrocarbons derived from
natural gas into natural gas liquids by means of a forced extraction
process. Forced extraction processes include but are not limited to
refrigeration, absorption (lean oil), cryogenic expander, and
combinations of these processes. Forced extraction does not include in
and of itself; natural gas dehydration, or the collection or gravity
separation of water or hydrocarbon liquids from natural gas at ambient
temperature or heated above ambient temperatures, or the condensation
of water or hydrocarbon liquids through passive reduction in pressure
or temperature, or portable dewpoint suppression skids.
* * * * *
    Horizontal well means a well bore that has a planned deviation from
primarily vertical to a primarily horizontal inclination or declination
tracking in parallel with and through the target formation.
* * * * *
    Natural gas means a naturally occurring mixture or process
derivative of hydrocarbon and non-hydrocarbon gases found in geologic
formations beneath the earth's surface, of which its constituents
include, but are not limited to, methane, heavier hydrocarbons and
carbon dioxide. Natural gas may be field quality, pipeline quality, or
process gas.
    Metering-regulating station means a station that meters the
flowrate, regulates the pressure, or both, of natural gas in a natural
gas distribution facility. This does not include customer meters,
customer regulators, or farm taps.
* * * * *
    Pressure groupings are defined as follows: less than or equal to 25
psig; greater than 25 psig and less than or equal to 60 psig; greater
than 60 psig and less than or equal to 110 psig; greater than 110 psig
and less than or equal to 200 psig; and greater than 200 psig.
* * * * *
    Sub-basin category, for onshore natural gas production, means a
subdivision of a basin into the unique combination of wells with the
surface coordinates within the boundaries of an individual county and
subsurface completion in one or more of each of the following four
formation types as designated by 18 CFR 270.305: conventional with >0.1
millidarcy permeability, and unconventional with <=0.1 millidarcy
permeability. Unconventional formation types are either shale, coal
seam, or other tight reservoir rock. Wells producing from more than one
unconventional formation type shall be classified into only one type
based on the formation with the most contribution to production as
determined by engineering knowledge. Unconventional wells producing in
two or more formation types of ``shale and coal seam'', ``shale and
other tight'', or ``shale, coal seam, and other tight''; are considered
shale. In addition, unconventional wells producing in ``coal seam and
other tight'' formations are considered coal.
    Transmission-distribution (TD) transfer station means a meter-
regulating station where a local distribution company takes part or all
of the natural gas from a transmission pipeline and puts it into a
distribution pipeline.
    Transmission pipeline means a Federal Energy Regulatory Commission
rate-regulated Interstate pipeline, a state rate-regulated Intrastate
pipeline, or a pipeline that falls under the ``Hinshaw Exemption'' as
referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-
717(w)(1994).
    Tubing diameter groupings are defined as follows: less than or
equal to 1 inch; greater than 1 inch and less than 2 inch; and greater
than or equal to 2 inch.
    Tubing systems means piping equal to or less than one half inch
diameter as per nominal pipe size.
* * * * *
    Vertical well means a well bore that is primarily vertical but has
some

unintentional deviation or one or more intentional deviations to enter
one or more subsurface targets that are off-set horizontally from the
surface location, intercepting the targets either vertically or at an
angle.
    Well testing venting and flaring means venting and/or flaring of
natural gas at the time the production rate of a well is determined
(i.e., the well testing) through a choke (an orifice restriction). If
well testing is conducted immediately after well completion or
workover, then it is considered part of well completion or workover.
    19. Table W-7 to subpart W is amended by:
    a. Revising the entries for ``Leaker Emission Factors--Above Grade
M&R at City Gate \1\ Stations Components, Gas Service,'' ``Population
Emission Factors--Below Grade M&R \2\ Components, Gas Service \3\,''
``Population Emission Factors--Distribution Mains, Gas Service \4\,''
and ``Population Emission Factors--Distribution Services, Gas Service
\5\.''
    b. Removing Footnote 1.
    c. Redesignating Footnotes 2, 3, 4, and 5 as Footnotes 1, 2, 3, and
4.
    The revisions read as follows:

------------------------------------------------------------------------
                              * * * * * * *
------------------------------------------------------------------------
Leaker Emission Factors--Transmission-distribution Transfer Station\1\
 Components, Gas Service
------------------------------------------------------------------------

                              * * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Below Grade Metering-Regulating station\1\
 Components, Gas Service\2\
------------------------------------------------------------------------

                              * * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service\3\
------------------------------------------------------------------------

                              * * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service\4\
------------------------------------------------------------------------

                              * * * * * * *
------------------------------------------------------------------------
\1\ Excluding customer meters.
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''

[FR Doc. 2011-21725 Filed 9-8-11; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register: January 26, 2009 (Volume 74, Number 15)]
[Notices]
[Page 4487-4491]
[DOCID:fr26ja09-131]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-59262; File No. SR-FINRA-2008-020]

Self-Regulatory Organizations; Financial Industry Regulatory
Authority, Inc.; Notice of Filing of Proposed Rule Change and Amendment
No. 2 Thereto Relating to Private Placements of Securities Issued by
Members

January 16, 2009.
    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
(``Act'' or ``Exchange Act'') \1\ and Rule 19b-4 thereunder,\2\ notice
is hereby given that on September 11, 2008, Financial Industry
Regulatory Authority, Inc. (``FINRA'') (f/k/a National Association of
Securities Dealers, Inc. (``NASD'')) filed with the Securities and
Exchange Commission (``SEC'' or ``Commission''), and amended on January
7, 2009,\3\ the proposed rule change as described in Items I, II, and
III below, which Items have been substantially prepared by FINRA. The
Commission is publishing this notice to solicit comments on the
proposed rule change from interested persons.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ Amendment No. 2 to SR-FINRA-2008-020. This amendment
replaced and superseded the original filing submitted to the SEC on
September 11, 2008. Amendment No. 1, which was filed on December 22,
2008, was withdrawn on January 7, 2009.
---------------------------------------------------------------------------

I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    FINRA is proposing to adopt new FINRA Rule 5122 (``Rule''). This
proposed rule change would require a member that engages in a private
placement of unregistered securities issued by the member or a control
entity to (1) Disclose to investors in a private placement memorandum,
term sheet or other offering document the intended use of offering
proceeds and the offering expenses, (2) file such offering document
with FINRA, and (3) commit that at least 85 percent of the offering
proceeds will be used for business purposes, which shall not include
offering costs, discounts, commissions and any other cash or non-cash
sales incentives.
    Amendment No. 2 to SR-FINRA-2008-020 makes minor changes to the
original filing filed on September 11, 2008. The proposed rule change
replaces and supersedes the proposed rule change filed on September 11,
2008 in its entirety, except with regard to Exhibit 2, NASD Notice to
Members 07-27 and comments received in response to NASD Notice to
Members 07-27.
    The text of the proposed rule change is available on FINRA's Web
site at http://www.finra.org, at the principal office of FINRA and at
the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, FINRA included statements
concerning the purpose of and basis for the proposed rule change and
discussed any comments it received on the proposed rule change. The
text of these statements may be examined at the places specified in
Item IV below. FINRA has prepared summaries, set forth in sections A,
B, and C below, of the most significant aspects of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

1. Purpose
Background and Discussion
    FINRA is proposing new FINRA Rule 5122 in response to problems
identified in connection with private placements by members of their
own securities or those of a control entity (referred to as ``Member
Private Offerings'' or ``MPOs''). In recent years, FINRA has
investigated and brought numerous enforcement cases concerning abuses
in connection with MPOs.\4\ Among the allegations in these cases were
that members failed to provide written offering documents to investors,
or provided offering documents that contained misleading, incorrect or
selective disclosure, such as omissions and misrepresentations
regarding selling compensation and the use of offering proceeds. In
addition, as part of its examination program, FINRA conducted a non-
public sweep of firms that had engaged in MPOs and found widespread
problems. The MPO sweep revealed that in some cases, offering proceeds
were used for individual bonuses, sales contest awards, commissions in
excess of 20 percent, or other undisclosed compensation.
---------------------------------------------------------------------------

    \4\ Franklin Ross, Inc., NASD No. E072004001501 (settled April
2006), summarized in NASD Notice Disciplinary Actions, p. 1 (May
2006); Capital Growth Financial, LLC, NASD No. E072003099001
(settled February 2006), summarized in NASD Notice Disciplinary
Actions, p. 1 (April 2006); Craig & Associates, NASD No.
E3B2003026801 (settled August 2005), summarized in NASD Notice
Disciplinary Actions, p. D6 (October 2005); Online Brokerage
Services, Inc., NASD No. C8A050021 (settled March 2005), summarized
in NASD Notice Disciplinary Actions, p. D5 (May 2005); IAR
Securities/Legend Merchant Group, NASD No. C10030058 (settled July
2004), summarized in NASD Notice Disciplinary Actions, p. D1 (July
2004); Shelman Securities Corp., NASD No. C06030013 (settled
December 2003), summarized in NASD Notice Disciplinary Actions, p.
D1 (February 2004); Neil Brooks, NASD No. C06030009 (settled June
2003), summarized in NASD Press Release, NASD Files Three
Enforcement Actions for Fraudulent Hedge Fund Offerings (August 18,
2003); Dep't of Enforcement v. L.H. Ross & Co., Inc., Complaint No.
CAF040056 (Hearing Panel decision January 15, 2005); Dep't of
Enforcement v. Win Capital Corp., Complaint No. CLI030013 (Hearing
Panel decision August 6, 2004). In addition to these cases, FINRA
has numerous ongoing investigations involving MPOs.
---------------------------------------------------------------------------

    Inasmuch as MPOs are private placements, they are not subject to
existing FINRA rules governing underwriting terms and arrangements and
conflicts of interest by members in public offerings.\5\ This proposed
rule change is intended to provide investor protections for MPOs that
are similar to the protections provided by NASD Rule 2720 for public
offerings by members.\6\
---------------------------------------------------------------------------

    \5\ FINRA Rule 5110 and NASD Rules 2720 and 2810 govern member
participation in public offerings of securities.
    \6\ Members would remain subject to other FINRA rules that
govern a member's participation in the offer and sale of a security,
including FINRA Rules 2010 and 2020 and NASD Rule 2310. Members also
are subject to the anti-fraud provisions of the federal securities
laws, including Sections 10(b), 11, 12 and 17 of the Exchange Act.
---------------------------------------------------------------------------

    In response to concerns about MPOs, in June 2007, FINRA issued
Notice to Members 07-27 (``NTM 07-27'') soliciting comment on a
proposed new rule regarding MPOs (then numbered Proposed Rule 2721).
FINRA received sixteen comment letters in response to NTM 07-27.\7\ The
comments were

varied. Some commenters expressed support for the intent of the
proposed rule, but voiced concerns about its breadth and scope; \8\
others questioned the benefit or necessity of the proposed rule.\9\
Most comment letters also suggested edits to the proposed rule.\10\ In
the discussion below, FINRA discusses the comments and note areas that
differ significantly from the Rule as previously proposed in NTM 07-27.
---------------------------------------------------------------------------

    \7\ The following is a list of persons and entities submitting
comment letters in response to NTM 07-27: Letter from Timothy P.
Selby for Alston & Bird LLP dated July 20, 2007 (Alston & Bird
letter); Letter from Keith F. Higgins for American Bar Association
Committee on Federal Regulation of Securities dated July 20, 2007
(ABA letter); Letter from Todd Anders dated July 13, 2007 (Anders
letter); Letter from Neville Golvala for ChoiceTrade dated July 19,
2007 (ChoiceTrade letter); Letter from Stephen E. Roth, et al of
Sutherland, Asbill & Brennan, LLP for the Committee of Annuity
Insurers dated July 20, 2007 (CAI letter); Letter from Peter J
Chepucavage for the International Association of Small Broker-
Dealers and Advisors dated July 20, 2007 (IASBDA letter); Letter
from Alan Z. Engel for LEC Investment Corp. dated June 14, 2007 (LEC
letter); Letter from Daniel T. McHugh for Lombard Securities Inc.
dated July 20, 2007 (Lombard letter); Letter from Dexter M. Johnson
for Mallon & Johnson, P.C. dated July 19, 2007 (Mallon & Johnson
letter); Letter from John G. Gaine for Managed Funds Association
dated July 20, 2007 (MFA letter); Letter from Curtis N. Sorrells for
MGL Consulting Corp. dated July 20, 2007 (MGL letter); Letter from
Thomas W. Sexton for the National Futures Association dated July 20,
2007 (NFA letter); Letter from Michael S. Sackheim and David A. Form
for the New York City Bar Committee of Futures and Derivatives
Regulation dated July 10, 2007 (NYC Bar letter); Letter from Joseph
A. Fillip, Jr. for PFG Distribution Co. dated July 19, 2007 (PFG
letter); Letter from Mary Kuan for Securities Industry and Financial
Markets Association dated July 27, 2007 (SIFMA letter); and Letter
from Bill Keisler for Stephens Inc. dated July 20, 2007 (Stephens
letter).
    \8\ See MFA letter; CAI letter; Alston & Bird letter.
    \9\ See Anders letter; Mallon & Johnson letter; ChoiceTrade
letter; ABA letter; SIFMA letter. FINRA does not agree with SIFMA
that the potential for abuses in connection with private offerings
by non-members is a reason to abandon the proposed rule change. The
FINRA staff believes that offerings by members raise unique
conflicts that require the protections of the proposed rule change.
FINRA also disagrees with SIFMA's contention that they do not have
legal authority to adopt the proposed rule change.
    \10\ See Alston & Bird letter; ABA letter; LEC letter; Mallon &
Johnson letter; MFA letter; MGL letter; PFG letter; SIFMA letter.
---------------------------------------------------------------------------

Definitions
    The proposed rule change states that no member or associated person
may offer or sell any security in a MPO unless certain conditions are
met. The proposed rule change uses the term ``MPO'' as ``a private
placement of unregistered securities issued by a member or control
entity.'' The proposed rule further defines two of the terms in the
definition of MPO: ``private placement'' and ``control entity.'' In
response to one comment,\11\ FINRA has defined the term ``private
placement'' to be ``a non-public offering of securities conducted in
reliance on an available exemption from registration under the
Securities Act.''
---------------------------------------------------------------------------

    \11\ See ABA letter; SIFMA letter.
---------------------------------------------------------------------------

    The proposed rule change defines the term ``control entity'' as
``any entity that controls or is under common control with a member, or
that is controlled by a member or its associated persons.'' The term
``control'' is defined as ``a beneficial interest, as defined in Rule
5130(i)(1), of more than 50 percent of the outstanding voting
securities of a corporation, or the right to more than 50 percent of
the distributable profits or losses of a partnership or other non-
corporate legal entity.'' \12\ The power to direct the management or
policies of a corporation or partnership alone (e.g., a general
partner)--absent meeting the majority ownership or right to the
majority of profits--would not constitute ``control'' as defined in
proposed FINRA Rule 5122. For purposes of this definition, entities may
calculate the percentage of control using a ``flow through'' concept,
by looking through ownership levels to calculate the total percentage
of control. For example, if broker-dealer ABC owns 50 percent of
corporation DEF that in turn holds a 60 percent interest in corporation
GHI, and ABC is engaged in a private offering of GHI, ABC would have a
30 percent interest in GHI (50 percent of 60 percent), and thus GHI
would not be considered a control entity under this definition.
---------------------------------------------------------------------------

    \12\ FINRA added language regarding ``other non-corporate legal
entities'' based on commenters' suggestions to clarify that control
would extend to entities other than corporations or partnerships.
See ABA letter; SIFMA letter.
---------------------------------------------------------------------------

    FINRA also reaffirms, as stated in NTM 07-27, that performance and
management fees earned by a general partner would not be included in
the determination of partnership profit or loss percentages. However,
if such performance and management fees are subsequently re-invested in
the partnership, thereby increasing the general partner's ownership
interest, then such interests would be considered in determining
whether the partnership is a control entity.
    In response to several comments advocating that the timing for
determining control take place at the conclusion rather than the
commencement of an offering,\13\ FINRA has revised the definition of
control to be determined immediately after the closing of an offering.
The definition also clarifies that, in the case of multiple closings,
control will be determined immediately after each closing. If an
offering is intended to raise sufficient funds such that the member
would not control the entity under the control standard, but fails to
raise sufficient funds, the member must promptly come into compliance
with the Rule, including providing the required disclosures to
investors and filings with FINRA's Corporate Financing Department
(``Department'').
---------------------------------------------------------------------------

    \13\ See Alston & Bird letter; ABA letter; LEC letter; MFA
letter; MGL letter; NYC Bar letter; SIFMA letter.
---------------------------------------------------------------------------

Disclosure Requirements
    The proposed rule change would require that a member provide a
written offering document to each prospective investor in an MPO,
whether accredited or not, and that the offering document disclose the
intended use of offering proceeds as well as offering expenses and
selling compensation.\14\ If the offering has a private placement
memorandum or term sheet, then such memorandum or term sheet must be
provided to each prospective investor and must contain these
disclosures. If the offering does not have a private placement
memorandum or term sheet, then the member must prepare an offering
document that discloses the intended use of offering proceeds as well
as offering expenses and selling compensation. The Rule is not meant to
require a particular form of disclosure; to emphasize this point, FINRA
proposes to issue Supplemental Material 5122.01, which would note that
nothing in the Rule shall require a member to prepare a private
placement memorandum that meets the additional requirements of
Securities Act Rule 502.
---------------------------------------------------------------------------

    \14\ Given that FINRA is not imposing limits on selling
compensation as it does in other rules, they do not believe it is
necessary to provide a detailed definition of ``selling
compensation'' as urged by SIFMA. FINRA believes that the term
``selling compensation'' for purposes of a disclosure requirement is
sufficiently clear.
---------------------------------------------------------------------------

    FINRA believes that every investor in an MPO should receive basic
information concerning the offering. FINRA also believes that none of
the disclosures required in the proposed rule change would conflict
with requirements under federal or state securities laws.\15\
---------------------------------------------------------------------------

    \15\ See SIFMA letter.
---------------------------------------------------------------------------

    In response to comments,\16\ the proposed rule change eliminates
the previously proposed requirements to disclose risk factors and ``any
other information necessary to ensure that required information is not
misleading.'' One commenter was concerned that requiring disclosure of
these items could lead to an inconsistent scheme of regulation in
interpreting the application of the federal securities laws to private
placements if FINRA's expectation of what should be disclosed

differed from the expectations of the SEC and the courts.\17\ While
FINRA has omitted these disclosures from the proposed rule change, they
specifically request comment on their decision to exclude such
disclosures.
---------------------------------------------------------------------------

    \16\ See ABA letter.
    \17\ See ABA letter.
---------------------------------------------------------------------------

Filing Requirements
    The proposed rule change would require that a member file a private
placement memorandum, term sheet or other offering document with the
Department at or prior to the first time such document is provided to
any prospective investor. Any amendments or exhibits to the offering
document also must be filed by the member with the Department within
ten days of being provided to any investor or prospective investor. The
filing requirement is intended to allow the Department to identify
those offering documents that are deficient ``on their face'' from the
other requirements of the proposed rule change. Notably, the filing
requirement in the proposed rule change differs from that in Rule 5110
(Corporate Financing Rule) in that the Department would not review the
offering and issue a ``no-objections'' letter before a member may
commence the offering.
    FINRA affirms, in response to concerns raised in the comment
letters,\18\ that information filed with the Department pursuant to
FINRA Rule 5122 would be subject to confidential treatment. FINRA has
included a provision in the proposed rule change explicitly clarifying
this position.\19\ The Department plans to develop a Web-based filing
system that would allow for the filing to be deemed filed upon
submission.\20\ In addition, the proposed rule change would not impose
any additional requirements regarding filing of advertisements or sales
materials, which would continue to be governed by NASD Rule 2210.\21\
---------------------------------------------------------------------------

    \18\ See ABA letter; Mallon & Johnson letter; SIFMA letter.
    \19\ See 5122(d). This confidential treatment provision is
similar to that provided in Rule 5110(b)(3).
    \20\ As noted supra, and in NTM 07-27, neither FINRA nor the
Department would issue a ``no objections opinion'' regarding any
offering document filed with the Department. However, if FINRA
subsequently determined that disclosures in the offering document
appeared to be incomplete, inaccurate or misleading, FINRA could
make further inquiries. The filing requirement also could facilitate
the creation of a confidential Department database on MPO activity
that would be used in connection with the member examination
process.
    \21\ See NYC Bar letter; SIFMA letter.
---------------------------------------------------------------------------

    One commenter suggested that a member's filing of Form D pursuant
to Securities Act Regulation D should provide sufficient information to
FINRA.\22\ FINRA staff disagrees. For example, FINRA notes that the
information in Form D does not include information on a wide variety of
expenses or applications of proceeds, nor does Form D require that such
information is contained in the offering documents.
---------------------------------------------------------------------------

    \22\ See Mallon & Johnson letter.
---------------------------------------------------------------------------

Use of Offering Proceeds
    Proposed Rule 5122(b)(3) would require that each time an MPO is
closed at least 85 percent of the offering proceeds raised be used for
business purposes, which would not include offering costs, discounts,
commissions or any other cash or non-cash sales incentives. The use of
offering proceeds also must be consistent with the disclosures to
investors, as described above. This requirement was created to address
the abuses where members or control entities used substantial amounts
of offering proceeds for selling compensation and related party
benefits, rather than business purposes. The proposed rule change does
not limit the total amount of underwriting compensation. Rather, under
the proposed rule change, offering and other expenses of the MPO could
exceed a value greater than 15 percent of the offering proceeds, but no
more than 15 percent of the money raised from investors in the private
placement could be used to pay these expenses. FINRA notes the 15
percent figure is consistent with the limitation of offering fees and
expenses, including compensation, in NASD Rule 2810 (Direct
Participation Programs), and the North American Securities
Administrators Association (``NASAA'') guidelines with respect to
public offerings subject to state regulation.
    Some commenters expressed concern that the 85 percent limit was
arbitrary or unnecessary \23\ and should be reduced or eliminated to
allow flexibility for management in MPOs.\24\ FINRA believes that when
a member engages in a private placement of its own securities or those
of a control entity, investors should be assured that, at a minimum, 85
percent of the proceeds of the offering are dedicated to business
purposes. FINRA recognizes that changing the business purpose or use of
proceeds in an offering may in some instances benefit investors, and
remind members that the member may change its use of proceeds, provided
it makes appropriate disclosure to investors and files the amended
offering document with the Department.
---------------------------------------------------------------------------

    \23\ See IASBDA letter; Mallon & Johnson letter; ABA letter;
SIFMA letter.
    \24\ See IASBDA letter; Mallon & Johnson letter; ABA letter.
---------------------------------------------------------------------------

    One commenter requested that, when an issuer plans a series of
MPOs, the issuer should be allowed to calculate the 85 percent limit at
the end of the series.\25\ FINRA believes, however, that the limit
should apply to each MPO in order to assure investors that at least 85
percent of each offering in a series is dedicated to the business
purposes described in that offering's offering document. As a result,
FINRA has clarified that the 85 percent limit applies to each MPO.
---------------------------------------------------------------------------

    \25\ See NYC Bar letter.
---------------------------------------------------------------------------

Proposed Exemptions
    Proposed Rule 5122 would include a number of exemptions for sales
to institutional purchasers because the staff's findings did not reveal
abuse vis-[agrave]-vis such purchasers, who are generally sophisticated
and able to conduct appropriate due diligence prior to making an
investment. Specifically, the proposed Rule would exempt MPOs sold
solely to the following:
     Institutional accounts, as defined in NASD Rule
3110(c)(4);
     Qualified purchasers, as defined in Section 2(a)(51)(A) of
the Investment Company Act;
     Qualified institutional buyers, as defined in Securities
Act Rule 144A;
     Investment companies, as defined in Section 3 of the
Investment Company Act;
     An entity composed exclusively of qualified institutional
buyers, as defined in Securities Act Rule 144A; and
     Banks, as defined in Section 3(a)(2) of the Securities
Act.
    In addition, the proposed rule change excludes the following types
of offerings, which do not raise the concerns identified in the sweep
or enforcement actions:
     Offerings of exempted securities, as defined by Section
3(a)(12) of the Exchange Act;
     Offerings made pursuant to Securities Act Rule 144A or SEC
Regulation S;
     Offerings in which a member acts primarily in a
wholesaling capacity (i.e., it intends, as evidenced by a selling
agreement, to sell through its affiliate broker-dealers, less than 20%
of the securities in the offering);
     Offerings of exempted securities with short term
maturities under Section 3(a)(3) of the Securities Act;
     Offerings of subordinated loans under SEA Rule 15c3-1,
Appendix D; \26\
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    \26\ Members' offerings of subordinated loans are subject to an
alternative disclosure regime. In 2002, the SEC approved a rule
change to require, as part of a subordination agreement, the
execution of a Subordination Agreement Investor Disclosure Document.
See Exchange Act Release No. 45954 (May 17, 2002), 67 FR 36281 (May
23, 2002); see also Notice to Members 02-32 (June 2002).

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     Offerings of ``variable contracts,'' as defined in NASD
Rule 2820(b)(2);
     Offerings of modified guaranteed annuity contracts and
modified guaranteed life insurance policies, as referred to in Rule
5110(b)(8)(E);
     Offerings of securities of a commodity pool operated by a
commodity pool operator, as defined under Section 1a(5) of the
Commodity Exchange Act;
     Offerings of equity and credit derivatives, including OTC
options, provided that the derivative is not based principally on the
member or any of its control entities; and
     Offerings filed with the Department under Rule 5110 or
NASD Rules 2720 or 2810.
    Finally, the proposed rule change also would exempt MPOs in which
investors would be expected to have access to sufficient information
about the issuer and its securities in addition to the information
provided by the member conducting the MPO. These exemptions include:
     Offerings of unregistered investment grade rated debt and
preferred securities;
     Offerings to employees and affiliates of the issuer or its
control entities; and
     Offerings of securities issued in conversions, stock
splits and restructuring transactions executed by an already existing
investor without the need for additional consideration or investments
on the part of the investor.
    This list of exemptions is largely based on the exemptions
previously proposed in NTM 07-27, with a few additions and
clarifications in response to comments.\27\ FINRA clarified that
exempted securities, as defined by Section 3(a)(12) of the Exchange
Act, would not be subject to the Rule.\28\ In addition, FINRA proposes
an exemption for commodity pools \29\ in view of the oversight and
regulation performed by the National Futures Association and the
Commodity Futures Trading Commission. FINRA also clarified that
variable contracts and other life insurance products \30\ would be
excluded, because the offer and sale of these types of offerings are
already subject to existing FINRA rules.\31\ FINRA also proposes an
exemption for member private offerings that are filed with the
Department under Rule 5110 or NASD Rules 2720 or 2810.
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    \27\ See Lombard letter; ABA letter; MGL letter; NYC Bar letter;
MFA letter; NFA letter; Alston & Bird letter; Anders letter; PFG
letter; CAI letter; ChoiceTrade letter; Mallon & Johnson letter;
SIFMA letter.
    \28\ Accordingly, FINRA notes that in connection with this
proposed Rule, they do not plan to recommend amending NASD Rule 0116
or the List of NASD Conduct Rules and Interpretive Materials that
apply to Exempted Securities. See CAI letter.
    \29\ See NYC Bar letter; MFA letter; NFA letter; Alston & Bird
letter; SIFMA letter.
    \30\ See CAI letter; PFG letter.
    \31\ See, e.g., NASD Rule 2820.
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    In addition, FINRA clarified aspects of other previously proposed
exemptions. FINRA clarified that their intent regarding the exemption
for wholesalers is to provide an exemption for those that do not
primarily engage in direct selling to investors.\32\ FINRA also
clarified that offerings of securities issued in conversions, stock
splits and restructuring transactions that are executed by an already-
existing investor without the need for additional consideration or
investment on the part of the investor would be exempt.\33\
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    \32\ See MGL letter; SIFMA letter.
    \33\ See Mallon & Johnson letter.
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    FINRA also noted that equity and credit derivatives, such as OTC
options, would be exempt, provided that the derivative is not based
principally on the member or any of its control entities.\34\ As a
technical matter, the issuer of an equity or credit derivative is the
member firm, and thus would make such offering an MPO. However, where
the security offered is not based principally on the member or any of
its control entities (e.g., an OTC option on MSFT), FINRA does not
believe such sale should be subject to the provisions of the proposed
rule change. On the other hand, if the derivative is based principally
on the member or a control entity (e.g., an OTC option overlying the
member), then the sale of such security should be treated as an MPO and
subject to the requirements of the proposed rule change.
---------------------------------------------------------------------------

    \34\ See SIFMA letter.
---------------------------------------------------------------------------

    Finally, FINRA clarified that the exemption for employees and
affiliates of issuers would apply to employees and affiliates of
control entities as well, because these persons are expected to have
access to a level of information about the securities of the issuer
similar to employees and affiliates of the issuer itself.\35\
---------------------------------------------------------------------------

    \35\ See Stephens letter; see also Lombard letter.
---------------------------------------------------------------------------

    Based on the comment letters,\36\ FINRA also reconsidered whether
offerings to accredited investors should be exempt. However, FINRA
continues to believe that an exemption for offerings made to accredited
investors would not be in the public interest due to the generally low
thresholds for meeting the definition of the term ``accredited
investor.'' FINRA notes that the SEC has recently proposed clarifying
and modernizing its ``accredited investor'' standard due to concerns
that the definition is overbroad.\37\
---------------------------------------------------------------------------

    \36\ See ChoiceTrade letter; PFG letter; SIFMA letter.
    \37\ See, e.g., Securities Act Release No. 8828 (Aug. 3, 2007),
72 FR 45116 (Aug. 10, 2007); Securities Act Release No. 8766 (Dec.
27, 2006), 72 FR 400 (Jan. 4, 2007).
---------------------------------------------------------------------------

    Additionally, it is FINRA's view that financial products offered by
a public reporting company,\38\ an investment fund \39\ or a state or
federal bank affiliate of a FINRA member \40\ should not be excluded
based solely on their status as a reporting company, a fund or a bank.
FINRA's belief is that, as a general matter, exemptions are best
tailored based on the type of securities offered or the type (and
sophistication) of the purchaser rather than the type of offeror. FINRA
also declines to exempt offerings that contribute below a specified
level of a member's net worth (e.g., 5%), to create a categorical
exemption for all exempted securities under Section 3(a) of the
Securities Act, or to expand the exemption for securities with short
term maturities under Section 3(a)(3) of the Securities Act to include
all securities with a maturity of nine months or less.\41\ As a
practical matter, however, many of these products would be exempt
because they meet one of the other exemptions enumerated in the Rule.
---------------------------------------------------------------------------

    \38\ See ABA letter; SIFMA letter.
    \39\ See MFA letter.
    \40\ See Anders letter; ABA letter.
    \41\ See SIFMA letter.
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Implementation and Compliance
    FINRA will announce the implementation date of the proposed rule
change in a Regulatory Notice to be published no later than 60 days
following Commission approval. The implementation date will be 30 days
following publication of the Regulatory Notice announcing Commission
approval, but will not apply retroactively to any offerings that have
already commenced selling efforts.
2. Statutory Basis
    FINRA believes that the proposed rule change is consistent with the
provisions of Section 15A(b)(6) of the Act,\42\ which requires, among
other things, that FINRA rules must be designed to prevent fraudulent
and manipulative acts and practices, to promote just and equitable
principles of trade, and, in general, to protect investors and the
public interest. FINRA believes the proposed rule change will provide
important investor protections in

connection with private placements of securities by members and control
entities.
---------------------------------------------------------------------------

    \42\ 15 U.S.C. 78o-3(b)(6).
---------------------------------------------------------------------------

B. Self-Regulatory Organization's Statement on Burden on Competition

    FINRA does not believe that the proposed rule change will result in
any burden on competition that is not necessary or appropriate in
furtherance of the purposes of the Act.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants, or Others

    The proposed rule change was published in Notice to Members 07-27
(June 2007). Sixteen comments were received in response to Notice to
Members 07-27. A copy of Notice to Members 07-27 is attached as Exhibit
2a to this rule filing. A list of the comment letters received in
response to Notice to Members 07-27 is attached as Exhibit 2b to this
rule filing. Copies of the comment letters received in response to
Notice to Members 07-27 are attached as Exhibit 2c to this rule filing.
The comments are summarized above.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    Within 35 days of the date of publication of this notice in the
Federal Register or within such longer period (i) as the Commission may
designate up to 90 days of such date if it finds such longer period to
be appropriate and publishes its reasons for so finding or (ii) as to
which the self-regulatory organization consents, the Commission will:
    (A) by order approve such proposed rule change, or
    (B) institute proceedings to determine whether the proposed rule
change should be disapproved.

IV. Solicitation of Comments

    Interested persons are invited to submit written data, views and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://
www.sec.gov/rules/sro.shtml); or
     Send an e-mail to<EMAIL_ADDRESS>Please include
File Number SR-FINRA-2008-020 on the subject line.

Paper Comments

     Send paper comments in triplicate to Elizabeth M. Murphy,
Secretary, Securities and Exchange Commission, 100 F Street, NE.,
Washington, DC 20549-1090.

All submissions should refer to File Number SR-FINRA-2008-020. This
file number should be included on the subject line if e-mail is used.
To help the Commission process and review your comments more
efficiently, please use only one method. The Commission will post all
comments on the Commission's Internet Web site (http://www.sec.gov/
rules/sro.shtml). Copies of the submission, all subsequent amendments,
all written statements with respect to the proposed rule change that
are filed with the Commission, and all written communications relating
to the proposed rule change between the Commission and any person,
other than those that may be withheld from the public in accordance
with the provisions of 5 U.S.C. 552, will be available for inspection
and copying in the Commission's Public Reference Room, 100 F Street,
NE., Washington, DC 20549, on official business days between the hours
of 10 a.m. and 3 p.m. Copies of such filing also will be available for
inspection and copying at the principal office of FINRA. All comments
received will be posted without change; the Commission does not edit
personal identifying information from submissions. You should submit
only information that you wish to make available publicly. All
submissions should refer to File Number SR-FINRA-2008-020 and should be
submitted on or before February 17, 2009.

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\43\
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    \43\ 17 CFR 200.30-3(a)(12).
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Florence E. Harmon,
Deputy Secretary.
 [FR Doc. E9-1466 Filed 1-23-09; 8:45 am]

BILLING CODE 8011-01-P


[Federal Register Volume 85, Number 161 (Wednesday, August 19, 2020)]
[Notices]
[Pages 51106-51107]
[FR Doc No: 2020-18218]

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SECURITIES AND EXCHANGE COMMISSION

Sunshine Act Meetings

TIME AND DATE: Notice is hereby given, pursuant to the provisions of
the Government in the Sunshine Act, Public Law 94-409, the Securities
and Exchange Commission will hold an Open Meeting on Wednesday,
September 16, 2020 at 10:00 a.m.

PLACE: The meeting will be held via remote means and/or at the
Commission's headquarters, 100 F Street NE, Washington, DC 20549.

STATUS: This meeting will begin at 10:00 a.m. (ET) and will be open to
the public via audio webcast only on the Commission's website at
www.sec.gov.

MATTERS TO BE CONSIDERED: The Commission will consider whether to
modernize and enhance the efficiency of the shareholder-proposal
process for the benefit of all shareholders by adopting amendments to
certain procedural requirements for the submission of shareholder
proposals and the provision relating to resubmitted proposals under
Rule 14a-8. The amendments being considered seek to modernize the
system for the first time in over 35 years and reflect many years of
engagement by Commission staff with investors, issuers and other market
participants.

CONTACT PERSON FOR MORE INFORMATION: For further information and to
ascertain what, if any, matters have been added, deleted or postponed,
please contact Vanessa A. Countryman, Office of the Secretary, at (202)
551-5400.

    Dated: August 14, 2020.
Vanessa A. Countryman,
Secretary.
[FR Doc. 2020-18218 Filed 8-17-20; 11:15 am]
BILLING CODE 8011-01-P