18 Cfr 260.8

Federal Energy Regulatory Commission
(1) The annual report for the year
ending December 2004 must be filed on
April 25, 2005.
(2) The annual report for each year
thereafter must be filed on April 18 of
the subsequent year.
(3) Newly established entities must
use projected data to determine whether FERC Form No. 2–A must be filed.
(4) The form must be filed in electronic format only, as indicated in the
General Instructions set out in that
form. The format for the electronic filing can be obtained at the Federal Energy Regulatory Commission, Division
of Information Services, Public Reference and Files Maintenance Branch,
Washington, DC 20426. One copy of the
report must be retained by the respondent in its files.
(Natural Gas Act, as amended, 15 U.S.C. 717–
717w; Natural Gas Policy Act of 1978, 15
U.S.C. 3301–3432; Federal Power Act, as
amended, 16 U.S.C. 792–828c; Department of
Energy Organization Act, 42 U.S.C. 7101–7352;
E.O. 12009, 3 CFR part 142 (1978))
[Order 101, 45 FR 60900, Sept. 15, 1980, as
amended by Order 390, 49 FR 32527, Aug. 14,
1984; Order 493, 53 FR 15031, Apr. 27, 1988;
Order 581, 60 FR 53071, Oct. 11, 1995; Order 628,
68 FR 269, Jan. 3, 2003; 69 FR 9044, Feb. 26,
2004]

§§ 260.4–260.7

[Reserved]

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§ 260.8 System flow diagrams: Format
No. FERC 567.
(a) Each Major natural gas pipeline
company, having a system delivery capacity in excess of 100,000 Mcf per day
(measured at 14.73 p.s.i.a. and 60 °F.),
shall file with the Commission by June
1 of each year five (5) copies of a diagram or diagrams reflecting operating
conditions on its main transmission
system during the previous twelve
months ended December 31. For purposes of system peak deliveries, the
heating season overlapping the year’s
end shall be used. Facilities shall be
those installed and in operation on December 31 of the reporting year. All
volumes shall be reported on a uniform
stated pressure and temperature base.
(b) The diagram or diagrams shall include the following items of information:
(1) Nominal diameter (inches) of each
pipeline.

§ 260.8
(2) Miles of pipeline (to nearest 0.1
mile) between points of intake, delivery, river crossings, storage fields,
crossovers, compressor stations and
connections with other pipeline companies.
(3) Direction of flow in the pipelines.
If direction of flow can be reversed at
compressor stations, so indicate.
(4) Maximum permissible operating
pressure for each pipeline at discharge
side of each compressor station or
other critical point, determined by the
Department of Transportation’s safety
standards.
(5) Total horsepower of compressor
engines installed at each compressor
station.
(6) Designed suction pressure for each
compressor station, p.s.i.g.
(7) Designed discharge pressure for
each station, p.s.i.g.
(8) Maximum volume, Mcf per day
that can be compressed at each compressor station under conditions of suction and discharge set forth in paragraphs (b) (6) and (7) of this section. If
direction of flow affects these factors
provide the information for each direction of flow.
(9) The fuel requirement at each compressor station under conditions described in paragraph (b)(8) of this section.
(10) Pressure in the pipeline at points
of emergency interconnection with
other pipeline companies which can
normally be expected to exist, and the
volume which could be delivered or received at such emergency interconnection points at such pressures. Give the
name of the interconnecting company.
(11) For each storage field, connected
to the system and operated by the respondent pipeline company, the maximum dependable daily and seasonal
withdrawal volumes available under
normal conditions of operation.
(12) Volumes delivered: (i) The average daily volumes delivered at each
takeoff point, (ii) the volumes delivered at each takeoff point on the day of
maximum coincidental delivery, and
(iii) the maximum daily volumes (noncoincidental) delivered to each customer under rates subject to FERC jurisdiction.

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§ 260.9

18 CFR Ch. I (4–1–12 Edition)

(13) The average daily volume received at each intake point to the
transmission pipeline system.
(14) The volume received into the
transmission pipeline system at each
intake point on the day of maximum
coincidental delivery.
(15) The information required by
paragraphs (b)(12), (13) and (14), of this
section may be furnished in tabular
form, or by reference to FERC Form
No. 2, providing, that the information
is suitably keyed to the diagram by appropriate identifying symbol or number.
[Order 303–A, 31 FR 7226, May 18, 1966, as
amended by Order 345, 32 FR 7332, May 17,
1967; Order 430, 36 FR 7052, Apr. 14, 1971; Order
215, 47 FR 10203, Mar. 10, 1982; Order 390, 49
FR 32527, Aug. 14, 1984]

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§ 260.9 Reports by natural gas pipeline
companies on service interruptions
and damage to facilities.
(a)(1) Every natural gas company
must report to the Director, Division
of Pipeline Certificates, at the earliest
feasible time:
(i) Damage to any jurisdictional natural gas facilities other than liquefied
natural gas facilities caused by a hurricane, earthquake or other natural disaster or terrorist activity that results
in a loss of or reduction in pipeline
throughput or storage deliverability;
and
(ii) Serious interruptions of service
to any shipper involving jurisdictional
natural gas facilities other than liquefied natural gas facilities. Such serious
interruptions of service shall include
interruptions of service to communities, major government installations
and large industrial plants outside of
communities or any other interruptions which are significant in the judgment of the pipeline company. Interruptible service interrupted in accordance with the provisions of filed tariffs,
interruptions of service resulting from
planned maintenance or construction
and interruptions of service of less
than three hours duration need not be
reported.
(2) In the event of damage to a natural gas company’s jurisdictional natural gas facilities other than liquefied
natural gas facilities by reason other
than hurricane, earthquake or other

natural disaster or terrorist activity,
the natural gas company should report
such damage if, in the natural gas company’s judgment, such damage creates
the potential for serious delivery problems on its own system or the pipeline
grid.
(b) Any report of damage to facilities
required by paragraph (a)(1)(i) of this
section, any report of service interruption required by paragraph (a)(1)(ii) of
this section and any report made pursuant to paragraph (a)(2) of this section
in a natural gas company’s discretion
must be submitted by the natural gas
company
by
e-mail
to
[email protected] or by facsimile
transmission to the Director, Division
of Pipeline Certificates, Office of Energy Projects at FAX number (202) 208–
2853.
(1) Reports required by paragraph
(a)(1)(i) or (ii) or made in a natural gas
company’s discretion pursuant to paragraph (a)(2) shall be made at the earliest feasible time and must state:
(i) The location and cause of the service interruption or damage to natural
gas pipeline or storage facilities;
(ii) The nature of any damage to
pipeline or storage facilities;
(iii) Specific identification of any facilities damaged;
(iv) The time the service interruption
or damage to facilities occurred;
(v) The customers affected by the
interruption of service or damage to facilities;
(vi) Emergency actions taken to
maintain service; and
(vii) Company contact and telephone
number.
(2) Following a report required by
paragraph (a)(1)(i) of this section of
damage to natural gas facilities resulting in loss of pipeline throughput or
storage deliverability or a report pursuant to paragraph (a)(2) of this section
in a natural gas company’s discretion,
the natural gas company shall report
to the Director, Division of Pipeline
Certificates, at the earliest feasible
time when pipeline throughput or storage deliverability has been restored.
(c) If so directed by the Commission
or the Director, Division of Pipeline
Certificates, the company must provide
any supplemental information so as to

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