IN THE UNITED STATES COURT OF APPEALS

FOR THE FIFTH CIRCUIT

 

No. 96-60536 

 

SEA ROBIN PIPELINE COMPANY;

Petitioner,

WILLIAMS GAS PROCESSING - GULF COAST COMPANY;

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

Intervenors

versus

FEDERAL ENERGY REGULATORY COMMISSION;

Respondent

PRODUCER-MARKETER TRANSPORTATION GROUP;

INDEPENDENT PETROLEUM ASSOCIATION OF AMERICA;

TOTAL MINATOME CORPORATION; 

ENERGY DEVELOPMENT CORPORATION;

EXXON CORPORATION; TEXACO NATURAL GAS INC; 

SHELL GAS TRADING COMPANY; PHILLIPS 

PETROLEUM COMPANY AND PHILLIPS GAS 

MARKETING COMPANY (“PHILLIPS”); 

MURPHY EXPLORATION AND PRODUCTION COMPANY; 

MARATHON OIL COMPANY; 

AMOCO PRODUCTION COMPANY AND 

AMOCO ENERGY TRADING CORPORATION (“AMOCO”); 

ANADARKO PETROLEUM CORPORATION,

Intervenors

 

Petition for Review of an Order of

the Federal Energy Regulatory Commission

 

October 23, 1997

Before POLITZ, Chief Judge, HIGGINBOTHAM and SMITH, Circuit Judges.
2

PATRICK E. HIGGINBOTHAM, Circuit Judge:

In 1995, the Sea Robin Pipeline Company petitioned the Federal

Energy Regulatory Commission for a declaration that Sea Robin’s

facilities perform a “gathering” function rather than a

“transportation” function, thus exempting them from the

Commission’s jurisdiction under Section 1(b) of the Natural Gas

Act, 15 U.S.C. § 717(b). The Commission, in denying the petition,

determined that Sea Robin was engaged in jurisdictional

transportation activities as opposed to gathering. The Commission

denied Sea Robin’s petition for rehearing. Sea Robin then

petitioned this Court for review. We are persuaded that the

Commission gave inadequate attention to the physical and

operational facilities of Sea Robin in applying its primary

function test. We grant the petition for review, vacate FERC’s

order and remand the case to the Commission. On remand, the

Commission may again consider the applicability of the primary

function test to offshore pipeline systems and, if necessary,

reformulate this test.

I.

The physical specifications of Sea Robin’s pipeline system are

central to deciding whether it is a transportation or a gathering

facility. Sea Robin’s pipeline system is located entirely offshore

in the Gulf of Mexico and approximately 90% of its facilities lie

in water depths of less than 140 feet. The system is configured in

the form of an inverted “Y” with two arteries stretching roughly
 

1 The pipeline is “dual-phase” in that it carries a raw

stream of natural gas and liquid hydrocarbons taken directly from

the gas wells.

3

southwest and southeast from a central point about fifty miles

south of the Louisiana coast. These two pipelines collect raw gas

from fifty-seven offshore production platforms. Sea Robin’s

Vermillion 149 Compressor Station stands at the intersection of

these two pipelines. It compresses the gas from the fifty-seven

platforms for travel north, up the inclined seabed, to the Erath

Compressor Station on the mainland. After collecting gas from four

more platforms, the system terminates near Erath, Louisiana, where

the gas is separated, dehydrated and processed. The Erath

Compressor Station then prepares the gas for delivery to downstream

transmission pipelines at five nearby entry points.

The Sea Robin system consists of 438 miles of dual-phase1

pipelines with a capacity to transport 1.26 billion cubic feet of

gas per day (Bcf/day) and includes around 69,500 hp of compression.

The total compression horsepower at the Vermillion 149 Station is

37,050 hp and is 32,490 hp at Erath, Louisiana. Of the 438 miles

of pipes, 339 miles are larger than twenty inches in diameter. The

remaining ninety-nine miles of pipes, mostly running from

individual platforms to the larger pipes, are between four and

sixteen inches in diameter. The longest segment is the Vermillion

149-Erath section, consisting of 66.3 miles of thirty-six inch

diameter pipeline running in a straight line from Sea Robin’s

Vermillion compressor station to onshore processing facilities.

The four platforms along this section are within twenty-five miles
 

2 See Christian S. Gerig, Appalachian Natural Gas and FERC.

Order 636: The Deregulation Dilemma, 24 Cap. U. L. Rev. 761, 762-63

(1995) (describing the three components of the natural gas

industry, namely, gathering, transmission, and distribution).

4

of the Vermillion compressor station, which means that the last

forty-one miles of the thirty-six inch diameter pipeline are

uninterrupted by lateral pipe segments. The gas and liquefiables

delivered by Sea Robin meet the merchantable natural gas quality

standards of downstream transmission pipelines.

II.

Section 1(b) of the Natural Gas Act, 15 U.S.C. § 717 et seq.,

governs “the transportation of natural gas in interstate commerce.”

See 15 U.S.C. § 717(b) (1988). In Section 1(b) Congress prescribed

not only “the intended reach of federal power, but also specif[ied]

the areas into which this power was not to extend.” Northwest

Central Pipeline Corp. v. State Corp. Comm’n, 489 U.S. 493, 510,

109 S.Ct. 1262, 1274, 103 L.Ed.2d 509 (1989) (quoting FPC v.

Panhandle E. Pipe Line Co., 337 U.S. 498, 503, 69 S.Ct. 1251, 1255,

93 L.Ed. 1499 (1949)). This Section expressly exempts from the

Commission’s jurisdiction “the production or gathering of natural

gas.”2 Thus, Congress “carefully divided” FERC’s regulatory power

and “did not envisage federal regulation of the entire natural-gas

industry field to the limit of constitutional power. Rather it

contemplated the exercise of federal power as specified in the

Act.” Id. 
5

Further, the Supreme Court has consistently held that

“exceptions to the primary grant of jurisdiction in Section 1(b)

are to be strictly construed,” Interstate Natural Gas Co. v. FPC,

331 U.S. 682, 690-91, 67 S.Ct. 1482, 1487, 91 L.Ed 1742 (1947), and

the terms “production” and “gathering” are to be “narrowly confined

to the physical acts of drawing the gas from the earth and

preparing it for the first stages of distribution.” Northern

Natural Gas Co. v. State Corp. Comm’n, 372 U.S. 84, 90, 83 S.Ct.

646, 649-50, 9 L.Ed.2d 601 (1963) (collecting cases); see also

Transcontinental Gas Pipe Line Corp. v. State Oil and Gas Bd., 474

U.S. 409, 418, 106 S.Ct. 709, 714-15, 88 L.Ed.2d 732 (1986);

Natural Gas Pipeline Co. v. Railroad Comm’n, 679 F.2d 51, 53-54

(5th Cir. 1982); Hamman v. Southwestern Gas Pipeline, Inc., 721

F.2d 140, 143 (5th Cir. 1983).

In the past, the Commission has employed three different

tests, namely, the behind-the-plant test, the central-point test,

and the primary function test, to determine whether a company’s

facilities qualify for the gathering exemption. Angela S.

Chitwood-Beehler, A Conflict in the Circuits: The FERC’s

Jurisdiction Over Gathering Rates, 13 Energy L.J. 375, 382 (1992).

The behind-the-plant test treats a system as a gathering facility

if it is located behind the gas processing plant which treats the

product coming from that area. Id.; In re Phillips Petroleum Co.,

10 F.P.C. 246, 277 (1951), overturned on other grounds by Phillips

Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed.

1035 (1954). The central-point test involves a determination of
6

where the separate and various lateral lines bring gas to a central

point for delivery into a single line. Angela S. Chitwood-Beehler,

supra at 382; Barnes Transportation Co., Inc., 18 F.P.C. 369

(1957).

More recently, the Commission rejected any bright-line

approach that employs a single, dispositive factor in favor of a

multi-factor, primary function test that analyzes the totality of

the facts and circumstances in a given case. In other words, under

the primary function test, the Commission determines whether, with

reference to the specific facts and circumstances of the particular

facility in question, its primary function is gathering. EP

Operating Co. v. FERC, 876 F.2d 46, 48 (5th Cir. 1989). Applying

this test in Farmland Industries, Inc., 23 FERC ¶ 61,063 (1983),

the Commission identified five salient factors in determining

whether a pipeline is a gatherer or a transporter:

(1) the diameter and length of the facility;

(2) the location of compressors and processing plants;

(3) the extension of the facility beyond the central point in

the field;

(4) the location of wells along all or part of the facility;

and 

(5) the geographical configuration of the system.

Id. at 61,143. The Commission later added a sixth factor: the

operating pressure of the line. EP Operating Co., 876 F.2d at 48.

No single Farmland factor is dispositive in the Commission’s

consideration of the facts and circumstances of a given case. See
7

Northwest Pipeline Corp. v. FERC, 905 F.2d 1403, 1408 (10th Cir.

1990).

In 1990, after this court’s decision in EP Operating Co. v.

FERC, 876 F.2d 46 (5th Cir. 1989), the Commission noted that

“because of recent advances in engineering and available

technology, offshore drilling operations continue to move further

offshore and further from existing interstate pipeline

connections,” and hence it would assess “the continuing viability

and relevance of the ‘primary function’ test to current industry

conditions.” Amerada Hess Corp., 52 FERC ¶ 61,268 (1990). The

Commission then proposed “a sliding scale which [would] allow the

use of gathering pipelines of increasing lengths and diameters in

correlation to the distance from shore and the water depth of the

offshore production area.” Id. at 61,988. The Commission also

stated that, in addition to the Farmland factors, it would take

into account non-physical criteria such as: 

(1) the purpose, location and operation of the facility; 

(2) the general business activity of the owner of the

facility; and 

(3) whether the jurisdictional determination is consistent

with the objectives of the Natural Gas Act and the Natural Gas

Policy Act.

Id.
8

III.

A.

An agency determination may be set aside if it is “arbitrary,

capricious, an abuse of discretion or otherwise not in accordance

with law.” 5 U.S.C. § 706(2)(A); EP Operating Co., 876 F.2d at 48.

The fundamental precept that permits this deferential standard of

review is that “an agency must cogently explain why it has

exercised its discretion in a given manner” and “must supply a

reasoned analysis” for any departure from other agency decisions.

Motor Vehicle Mfrs. Ass’n v. State Farm, 463 U.S. 29, 48, 57, 103

S.Ct. 2856, 2869, 2874, 77 L.Ed.2d 443 (1983). However, “a court

is not to substitute its judgment for that of the agency” or

“supply a reasoned basis for the agency’s action that the agency

itself has not given.” Id. at 43, 103 S.Ct. at 2867 (quoting SEC

v. Chenery Corp., 332 U.S. 194, 196, 67 S.Ct. 1575, 1577, 91 L.Ed.

1995 (1947)).

Treating the first Farmland factor, the length and diameter of

the facility, the Commission decided that “based on the very large

size of [Sea Robin’s] system, th[e] demarcation between gathering

and transmission [was] clearly evident. In other words, the length

and diameter of the system’s components, as well as its overall

size, [we]re not outweighed by other elements of the ‘primary

function’ test.” Sea Robin Pipeline Co., 71 FERC ¶ 61,351, 62,398

(1995) (emphasis in original). 

Then the Commission examined other elements of the primary

function test. It concluded that the behind-the-plant factor was
 

3 The Commission urges that we have no jurisdiction to review

its orders with regard to the location of wells Farmland factor

since Sea Robin did not challenge its orders with respect to this

particular factor. We find that the record establishes that Sea

Robin did raise this objection adequately in its petition for

rehearing to satisfy the requirements of 15 U.S.C. § 717r(b).

9

of “little relevance,” and the reality of how gas is processed on

the outer continental shelf (OCS) reduced the weight accorded to

this factor. Id. at 62,401. Similarly, the Commission found the

central point in the field factor “to be of limited importance with

regard to isolated OCS operations”; the operating pressure to be a

“neutral criteria in applying the primary function test to OCS

facilities”; the location of wells factor3 to be “not

determinative”; and the geographical configuration of Sea Robin’s

system to be simply “in large part a function of the location of

areas in the OCS that were in need of transportation services.”

Id. at 62,401-02.

The Commission repeatedly emphasized that the non-physical

criteria in its test supported its conclusion that Sea Robin was a

transporter, particularly Sea Robin’s prior certification as a

jurisdictional pipeline and its ownership by an interstate

pipeline, the Southern Natural Gas Company, as opposed to a

producer of gas. Finally, the Commission urged that granting

gathering status to Sea Robin would amount to deregulation of the

entire natural gas pipeline system on the outer continental shelf.
10

B.

Sea Robin’s system resists easy categorization because the

logistics of offshore pipelines obscures differences between

gathering gas from Gulf platforms and transporting it to the

mainland. Since it is not feasible to process raw gas on open

water, entities like Sea Robin do not have an opportunity to gather

the gas at a local, centralized point to prepare it for traditional

transportation. Instead, they must construct large pipes to carry

(often over a hundred miles away) the raw gas from offshore rigs to

the shore for processing. In short, the pattern of gathering and

distribution on shore differs from the pattern of transportation

and gathering of gas from the middle of the Gulf to the mainland.

See Edwin I. Malet, Outer Continental Shelf Oil Pipelines Under The

Interstate Commerce Act, 43 La. L. Rev. 1143, 1172-73 (1983)

(noting that it “is unclear whether or under what circumstances the

business of ‘gathering’ may be considered a transportation service

subject to regulation.... Indeed, most, if not all, offshore oil

movement might be characterized as gathering.”). Nevertheless,

Section 1(b) of the Natural Gas Act requires that the Commission

reckon with this statutory distinction between gatherers and

transporters and provide a framework for making a meaningful

distinction between the two, in the context of offshore pipelines.

It appears that the very size of Sea Robin’s system led the

Commission to conclude presumptively that it is a transportation

facility. In so doing, the Commission retracted its prior

acknowledgment that the efficiencies associated with moving large
11

volumes of gas to shore may require the use of large diameter

pipelines. The Commission abandoned, without reasoned

consideration, its “sliding scale” of Amerada Hess that would

“allow the use of pipelines of increasing lengths and diameters in

correlation to the distance from shore and the water depth of the

production area.” Instead, the Commission reverted to its single

factor, bright-line approaches that it had previously rejected as

unworkable for offshore pipelines. See Northwest Pipeline Corp.,

905 F.2d at 1409 (noting that a reasoned analysis of the primary

function test must eschew the application of any overarching bright

line standards); EP Operating Co., 876 F.2d at 48. 

The Commission purported to work through all the factors in

its primary function test. Yet it excluded at least four factors

on grounds that they did not shed light on the problem because of

the distinctive considerations involved in retrieving gas from the

outer continental shelf. The Commission found that over half of

its own physical Farmland factors were not probative in the

offshore context and should therefore be excluded without any

application to the Sea Robin system. While we recognize that every

factor in the primary function test may not apply in every

situation, by excluding consideration of a large number of the

Farmland factors, the Commission, in effect, reduced the primary

function analysis to a litmus test that turned on the length and

diameter of the overall system.

The Commission must apply consistently its primary function

test and not discount, without reasoned analysis, application of
12

any factor which points to a non-jurisdictional result. It may not

“disregard those facts or issues that prove difficult or

inconvenient” or “refus[e] to come to grips” with certain results

in applying the primary function test. Tenneco Gas v. FERC, 969

F.2d 1187, 1214 (D.C. Cir. 1992).

Relatedly, the Commission’s accent on business purpose,

ownership, and prior certification status misses the basic thrust

of the primary function test -- making a technical distinction

between gathering and transportation based on the physical and

operational characteristics of a pipeline facility. See Northwest

Pipeline Corp., 905 F.2d at 1407 n.10, 1410 (noting that “the

production and gathering exemption applies to the physical

activities, facilities, and properties used in the production and

gathering of natural gas and not to the business of production and

gathering” and a company’s “status in interstate transportation

cannot alone transform the character of [its] facilities”)

(citations omitted). Congress made its policy choices regarding

the reach of regulation. It did not make these choices by defining

goals and objectives, leaving their implementation to the

administrative agency. Rather, Congress drew a distinction based

on the physical patterns of the industry, gathering versus

transporting. It is this Congressional choice that demands that

the Commission define its jurisdictional reach in distinctions

between gathering and transporting. If the Commission is to remain

tethered to the statute, as it must, that inquiry must be based

primarily on physical criteria and the realities of the field. The
13

inquiry cannot be cut loose to locate a different inquiry that

Congress might have directed had it foreseen the offshore

development and the patterns emerging from deregulation. It is a

statute we are construing. 

Further, the Commission’s emphasis on ownership may be called

into question in light of its recent practice of allowing pipeline

companies to spin-off affiliated gatherers and thus make them nonjurisdictional. See, e.g., Pacific Gas & Elec. Co. v. FERC, 106

F.3d 1190, 1196-97 (5th Cir. 1997), cert. denied, 66 U.S.L.W. 3254

(U.S. Oct. 6, 1997) (No. 96-1847); Conoco, Inc. v. FERC, 90 F.3d

536 (D.C. Cir. 1996), cert. denied, 117 S.Ct. 1017 (1997) (both

allowing a wholly-owned gathering facility to escape FERC

jurisdiction). In short, general business activity and prior

certification are relevant, but they are only part of the mix. We

do not intend to cast a shadow on the Commission’s OCS Policy

Statement regarding consideration of non-physical criteria. See 74

FERC at ¶ 61,759. Rather, we intend that it be put in its place as

considerations secondary to the physical factors. The

determinative question is when did gathering cease and

transportation commence. Non-physical factors must be relevant to

this question.

The Commission raises the potential for a “regulatory gap”

problem by urging that if Sea Robin is found to be a gathering

system, then other large gas transporters may seek similar

declarations, thus upsetting the investment-backed expectations of

producers and shippers who have come to rely upon the Commission’s
 

4 The Commission declined to address Sea Robin’s request

urging the Commission to find “at a minimum Sea Robin’s facilities

at and upstream of the Vermillion 149 platform...be declared to be

non-jurisdictional gathering facilities under the NGA”, because

the request was not part of the original petition. The Commission

noted that its decision was without prejudice. See 75 FERC ¶

62,084 n.90.

14

exercise of regulatory authority. Need for regulation cannot alone

create authority to regulate. Commission jurisdiction must be

defined by first turning to a reasoned application of the primary

function test. See Northwest Pipeline Co., 905 F.2d at 1412. We

do not suggest that the formulation of a primary function test must

be blind to its consequences. But the look at consequences is not

the beginning point; it is a reality check. 

On remand, the Commission may reformulate its primary function

test. It may choose to discontinue criteria not relevant to the

physical, geographical and operational characteristics of pipelines

in the OCS. The record suggests other criteria, such as the

quality of gas in the pipelines and the depth of the water in the

offshore production area, that may be relevant to the inquiry.

Finally, Sea Robin may choose to respond to the Commission’s

invitation to offer portions of its system as predominantly

involved in a gathering or a transportation function.4 Discomfort

in drawing the jurisdictional line at points internal to an overall

system may be soothed with the reminder that Congress did not

intend to extend FERC’s jurisdiction to all natural gas pipelines;

indeed it demands the drawing of jurisdictional lines, even when

the end of gathering is not easily located (consider, for example,
15

a distinction between the field south of the Vermillion Compressor

Station and the pipelines leading north to Erath, Louisiana).

IV.

The Commission has failed to supply the requisite reasoned

analysis in applying its primary function test. We GRANT the

petition for review, VACATE the Commission’s order and REMAND the

case for further consideration by the Commission. On remand, the

Commission may reconsider the applicability of the factors in its

primary function test to offshore pipeline systems and then, if

necessary, reformulate this test.

VACATED AND REMANDED.