03-21373. Application of the Primary Function Test for Gathering on the Outer Continental Shelf; Notice of Public Conference

August 14, 2003.

Take notice that on September 23, 2003, the Commission will convene a public conference in the above captioned proceeding. The purpose of the conference will be to explore whether the Commission should reformulate its test for defining nonjurisdictional gathering in the shallow waters of the Outer Continental Shelf (OCS) and if so what the new test should be.

The Commission has considered its offshore gathering policy a number of times in the past decade.^[1] Nevertheless, a satisfactory definition of gathering under the Natural Gas Act has remained elusive. A clear, consistent approach to offshore gathering is needed to protect producers and customers from the market power of third party transporters and to avoid different jurisdictional outcomes for companies that perform essentially the same economic function.

Background

A. Evolution of the Primary Function Test

Although section 1(b) of the Natural Gas Act states that the provisions of that act do not apply “to the production or gathering of natural gas,” the act itself does not define those terms. The Commission has defined gathering as “the collecting of gas from various wells and bringing it by separate and several individual lines to a central point where it is delivered into a single line.” ^[2] The Supreme Court has added that “production” and “gathering” are terms “narrowly confined to the physical acts of drawing the gas from the earth and preparing it for the first stages of distribution.” ^[3] These definitions have been useful in describing gathering as a concept. Nevertheless, as the courts have recognized, “the line between gathering and transportation is inherently elusive.” ^[4] Attempts to establish a functional test, useful in the context of specific proceedings, resemble the pursuit of a desert mirage. Historically, the tendency has been to announce a particular physical characteristic that could be used to identify nonjurisdictional gathering, only to substitute other criteria later to reflect changes in the industry or in the evolution of Commission policy.^[5] In Farmland Industries, Inc.,^[6] the Commission identified a number of factors for consideration in analyzing the section 1(b) gathering test, and stated that “the ultimate test is whether the primary function can be classified as transportation or gathering.” The primary function test factors included:

• The length and diameter of a pipeline (longer and wider pipe indicating transportation);
• The central point in a field;
• The pipeline's geographic configuration (a web-like pattern, for example, suggesting a gathering function)
• Location of compressors and processing plants (i.e., the “behind the plant” test);
• The location of wells along all or part of the facilities (typically indicating gathering); and
• Operating pressure of a line, with higher pressure generally associated with the need to propel gas in a transportation function.

The primary function test has been relatively satisfactory for analyzing onshore facilities. Offshore, however, the test has proven more difficult to apply.^[7] Thus, in EP Operating Co. v. FERC, 876 F.2d 46, 48-49 (5th Cir. 1989), the Commission initially ruled that under the primary function test the offshore platform where initial gas treatment took place constituted a “central point in the field” where the gathering function was complete, and therefore the 51-mile long, 16-inch diameter OCS pipeline downstream of the platform at issue in that case was a jurisdictional transportation facility. The court reversed that finding, holding that while the length and diameter of pipeline facilities might indicate a transportation function onshore, those factors had less weight in the offshore context because of the longer distances between the point of production in deep water and the nearest connection with an interstate pipeline. The court further questioned the validity of a central-point-in-the-field analysis applied to unitary OCS structures.

In response, the Commission modified its primary function test for the OCS, stating that as drilling operations pushed further offshore from existing interstate pipeline connections, it would apply a sliding scale to allow for the increasing length and diameter appropriate for gathering lines in correlation to the distance from shore and the water depth of the offshore production area.^[8] Later, following a conference on offshore gathering in Docket No. RM96-5-000, the Commission issued a policy statement announcing that it would “presume facilities located in deep water [more than 200 meters] are primarily engaged in gathering or production.” ^[9]

As with onshore facilities, the use of the primary function test, as modified by the policy statement for deepwater facilities, seems to be workable, and there has been relatively little controversy concerning its application in recent years. Efforts to apply the primary function test to offshore facilities in the shallow OCS, however, have been contentious.

B. The Sea Robin Pipeline

Difficulties applying the primary function test to offshore facilities were highlighted by the Commission's decision in Sea Robin Pipeline Company (Sea Robin).^[10] Sea Robin's offshore pipeline facilities were certificated as jurisdictional transmission facilities by the Commission in 1969. The system consists of 438 miles of pipeline that transports unprocessed gas from shallow water on the OCS to a processing plant onshore. The system is configured in the form of a “Y”. Along the two arms of the “Y”, 45 lateral lines with diameters ranging from 4.5 to 30 inches are connected to 67 receipt points located on production platforms, or at subsea taps. Through those upstream arms, Sea Robin moves the gas to a manned platform with two turbine compressor units at the fork of the “Y” closer to shore. The bottom line of the “Y”, from the platform to shore, consists of 66.3 miles of 36-inch pipeline. Along this segment the gas is mingled with additional gas from four platforms.

In response to a request to reclassify the Sea Robin facilities from transmission to gathering, the Commission found that the primary function of Sea Robin's entire system was and continued to be jurisdictional transportation. In reaching that conclusion, the Commission emphasized the length and size of Sea Robin's pipeline, and also certain non-physical factors, such as the reliance of shippers in the original jurisdictional determination. The U.S. Court of Appeals for the Fifth Circuit remanded that decision.^[11] In doing so the court said the Commission had relied too heavily on the size of Sea Robin's system as a determinative factor and did not give enough consideration to the different nature of gathering on the OCS. The court also faulted the Commission for reliance on non-physical considerations, such as Sea Robin's ownership and shipper expectations. The court specifically found that the Commission's consideration of a “regulatory gap” in the absence of Natural Gas Act jurisdiction was inappropriate: “Need for regulation cannot alone create authority to regulate.” ^[12]

In its decision, the court suggested that the primary function test could be adapted to the operational characteristics of the OCS, so that portions of its system could be considered to be predominantly gathering and other parts predominantly transportation. On remand, then, the Commission adopted this suggestion and reformulated the primary function test to draw the jurisdictional line at an internal point on the Sea Robin system, at the junction of the “Y”.^[13] The Commission concluded that the part of Sea Robin's pipeline facilities from the platform to shore was a jurisdictional transportation system. Upstream of that point the two legs of the “Y” formed a non-jurisdictional gathering system.

In reformulating its primary function test, the Commission concluded that the “behind-the-plant” factor is not necessarily determinative of where gathering ends when applied to offshore facilities. In addition, the Commission announced that where a pipeline system includes a facility where gas is delivered by several relatively small diameter lines for aggregation and preparation for further delivery onshore through a single larger diameter pipeline, the location of that collection facility will be afforded considerable weight for purposes of identifying the demarcation point between gathering and transportation on OCS systems.^[14]

Although not all OCS pipeline systems exhibit such a centralized aggregation point, e.g., facilities with a straight-line or spine-and-lateral type configuration, the presence of such a location would be considered the offshore analogue of the onshore “central-point-in-the-field” criterion.

The Commission's decision on remand, based on its reformulated test that included the central point of aggregation as a factor offshore, was upheld by the U.S. Court of Appeals for the District of Columbia Circuit in Exxon (note 4 supra).^[15]

C. The “Reformulated, Modified Primary Function Test”

Despite the several modifications of the primary function test described above, its utility in identifying nonjurisdictional gathering facilities remains uneven. As mentioned, the rule seems to work fairly well onshore, possibly because where other factors are not conclusive, there is usually a processing plant located at the end of a gathering system that serves as a logical demarcation point between jurisdictional and nonjurisdictional systems. Also, after an initial round of decisions interpreting the 1996 Policy Statement applying the primary function test to facilities located in deep water beyond the OCS, there has been relatively little controversy. In the shallow areas on the OCS, on the other hand, the status of facilities remains unsettled. The Commission continues to receive requests to reclassify jurisdictional transmission facilities as gathering, over the objection of customers who have been served through the facilities. In these types of cases, the correct interpretation of the primary function test is usually the main issue.

Based on the number of contested cases presented to us, we are concerned about the high degree of uncertainty that seems built into the primary function test as applied offshore. The primary function test lists numerous factors for consideration, with no one factor having priority. Thus, for example, the size of a particular system may suggest that it is transmission, but the configuration may suggest gathering. The primary function test does not indicate how such inconsistencies should be resolved. The result, over time, has been the gradual reclassification of more and larger systems as gathering, even in cases where systems had been regulated for many years under the Natural Gas Act. Systems with generally similar physical characteristic may have a different regulatory status because of relatively minor physical differences. This result can produce different regulatory results for competitors who perform essentially the same economic function. It is also seems unfair to customers who may have made investments relying on the regulated status of a transporter, only to find themselves subject to the market power of that transporter in its new deregulated form. The “need for regulation” may not create authority to regulate; on the other hand, inconsistent classification and regulatory treatment cannot be what Congress intended when it established a comprehensive scheme of federal regulation that included transportation from the OCS.

Public Conference

The Commission is convening a public conference to hear suggestions from interested persons on developing a new test for gathering on the OCS that is reasonably objective and that furthers the regulatory goals of the Natural Gas Act. (The conference will not include the policy adopted for deepwater facilities in Docket No. RM96-5-000.) A new test should ensure that similar facilities are subject to similar regulatory treatment. It should also provide incentives for investment in production, gathering, and transportation infrastructure offshore, without subjecting producers to the unregulated market power of third party transporters. Persons who appear at the conference should be prepared to indicate how the Commission's definition of gathering can be changed to achieve these goals. Persons seeking to make formal statements at the public conference should be prepared to address questions set forth below. Other questions may arise during the course of the proceedings.

Questions

1. To what extent should a gathering test that be based on the length and diameter of the pipeline, the extent the facilities are operationally integrated with either production or transportation facilities, the function of compression in relation to the facilities, and the proximity to the pipeline transportation grid?

2. To what extent should the location of processing plants, the central point of aggregation, the operating pressure of a line, and geographic configuration of facilities, be considered relevant in evaluating the status of facilities on the OCS? What are the advantages and disadvantages of relying on these factors? Are there any other factors that should be considered?

3. What should be the relevance of non physical factors such as a facility's history of regulation or the major business purpose of an owner?

4. If formerly certificated facilities are determined to be gathering, may the Commission nonetheless require the company to file for abandonment under section 7(b) of the Natural Gas act before the facilities may be transferred to another company?

Procedures

The public conference convened by this notice will be held on September 23, 2003 at the offices of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. All interested persons are invited to attend. Persons interested in speaking or making a presentation should indicate their interest no later than September 3, 2003 by a letter addressed to the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, and should refer to Docket No. AD03-13-000. Each request to participate must include the name of a contact person, their telephone number and e-mail address. There is no need to provide advance notice to the Commission simply to attend the conference.

Comments addressing the questions set out in this notice may also be filed by September 3, 2003. Every effort will be made to accommodate requests to make presentations, but depending on the number of requests received, a limit may have to be placed on the number of presenters and the time allowed for presentations.

Members of the Commission intend to participate in the public conference and will reserve time for questions and answers. In a subsequent notice, we will provide further details on the conference, including the agenda and a list of participants, as plans evolve. For additional information, please contact Gordon Wagner, Office of General Counsel, phone [phone], e-mail: [e-mail].

Magalie R. Salas,

Secretary.

Footnotes

1.  See generally Natural Gas Gathering Services Performed by Interstate Pipelines and Interstate Pipeline Affiliates —Issues Related to Rates and Terms and Conditions of Service, Docket No. RM94-4-000, Notice of Public Conference, 65 FERC ¶ 61,136 (1993); Gas Pipeline Facilities and Services on the Outer Continental Shelf—Issues Related to the Commission's Jurisdiction Under the Natural Gas Act and the Outer Continental Shelf Lands Act, Docket No. RM96-5-000, Policy Statement, 74 FERC ¶ 61,222 (1996) (1996 Policy Statement); Chevron U.S.A., Inc. v. FERC, 193 F. Supp. 2d 54 (D.DC, January 11, 2002), appeal pending sub nom. Williams Companies, et al. v. FERC, No. 02-5056 (DC Cir.) (appeal of district court ruling on motion that FERC did not have authority under the Outer Continental Shelf Lands Act (OCSLA) to issue regulations requiring gas service providers on the Outer Continental Shelf (OCS)to submit quarterly reports of services provided).

2.  Lomak Petroleum, Inc. v. FERC, 206 F.3d 1193, 1196 (DC Cir 2000), quoting from Barnes Transportation Company, 18 FPC at 372 (1957). See also Conoco, Inc. v. FERC, 90 F.3d 536, 539 n.2 (DC Cir. 1996)(”Gathering is the process of taking natural gas from the wells and moving it to a collection point for further movement through the pipeline's principal transmission system.”) (quoting Northwest Pipeline Corp. v. FERC, 905 F.2d 1403, 1404 n.1 (10th Cir. 1990)).

3.  Northern Natural Gas Co. v. State Corp. Comm'n, 372 U.S. 84, 90 (1963).

4.  Exxon Mobil Gas Marketing Company v. FERC (Exxon), No. 00-1355 (DC Cir. August 6, 2002) (Judge Edwards dissenting) slip op. at 18, citing Conoco, Inc. v. FERC 90 F. 3d 536 at 542 (DC Cir. 1996).

5.  For many years, the Commission employed two principal tests to differentiate (primarily onshore) transportation from gathering facilities. The “behind-the-plant” test presumes that all facilities located between the wellhead and a processing plant are non-jurisdictional gathering lines, while facilities downstream of the processing plant are presumptively transportation facilities. See Phillips Petroleum Co., 10 FPC 246 (1951), rev'd in part on other grounds sub nom. Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672 (1954). For gas that required no processing, the “central-point-in-the-field” test applied, under which lateral lines that collect gas from separate wells before converging into a larger single line—typically at the point where the gas is compressed for transportation by the pipeline—were classified as gathering facilities. E.g., Barnes, supra

6.  23 FERC ¶ 61,063 at 61,143 (1983). The Commission later added a number of “non-physical” criteria, including (1) the purpose, location and operation of a facility; (2) the business of the owner; (3) whether the jurisdictional determination is consistent with the objectives of the NGA and other legislation; and (4) the changing technical and geographic nature of exploration and production. Amerada Hess Corp., 52 FERC ¶ 61,268 at 61,844-45 (1990). Under the primary function test, no one factor is determinative, nor do all factors apply in every situation. See e.g., Williams Field Services, 194 F.3d at 116; Farmland, 23 FERC at 61,143.

7.  As more new facilities were constructed offshore on the OCS, where the pattern of gathering and distribution differs, the applicability of the factors was questioned. Specifically, it is often not feasible to process raw gas on open water. As a result, pipelines on the OCS typically do not gather gas at a local, centralized point within a producing field as they would onshore, to prepare it for traditional transportation. Rather, on the OCS, they construct relatively long lines to carry the raw gas from offshore platforms, where after production only rudimentary gas treatment takes place (primarily to remove water), to the shore or a point closer to shore where it can be processed into “pipeline quality” gas that can be transported by an interstate pipeline.

8.  See Amerada Hess, 52 FERC at 61,988 (1990).

9.  See 1996 Policy Statement, note 1 supra.

10.  71 FERC ¶ 61,351 (1995), reh'g denied, 75 FERC ¶ 61,332 (1996).

11.  Sea Robin Pipeline Company v. FERC, 127 F.3d 365 (5th Cir. 1997).

12.  Id. at 371.

13.  Sea Robin Pipeline Company, Order on Remand, 87 FERC ¶ 61,384 (1999) (Comm. Bailey dissenting), rehearing denied, 92 FERC ¶ 61,072 (2000).

14.  87 FERC at 62,248.

15.  See also Williams Gas Processing—Gulf Coast Company, L.P. et al. v. FERC, No. 01-1327 (DC Cir. June 20, 2003).