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Proposed Rule

Revisions to Indexing Policies and Page 700 of FERC Form No. 6

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Start Preamble Start Printed Page 76315


Federal Energy Regulatory Commission, Department of Energy.


Advance notice of proposed rulemaking.


The Commission seeks comment regarding potential modifications to its policies for evaluating oil pipeline indexed rate changes. The Commission also seeks comment regarding potential changes to FERC Form No. 6, page 700. The Commission invites all interested persons to submit comments in response to the proposals.


Initial Comments are due December 19, 2016, and Reply Comments are due January 31, 2017.


Comments, identified by docket number, may be filed in the following ways:

  • Electronic Filing through Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format.
  • Mail/Hand Delivery: Those unable to file electronically may mail or hand-deliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426.

Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures section of this document.

Start Further Info


Adrianne Cook (Technical Information), Office of Energy Market Regulation, 888 First Street NE., Washington, DC 20426, (202) 502-8849

Monil Patel (Technical Information), Office of Energy Market Regulation, 888 First Street NE., Washington, DC 20426, (202) 502-8296

Andrew Knudsen (Legal Information), Office of the General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502-6527

End Further Info End Preamble Start Supplemental Information


Table of Contents

Table of ContentsParagraph numbers
I. Background4
II. Indexing Policies7
III. Modifications to Page 70013
A. Background14
B. Supplemental Page 700s16
C. Additional Reporting Requirements on Page 70022
IV. Burden31
V. Comment Procedures31
VI. Document Availability32

1. The Federal Energy Regulatory Commission (Commission) is considering modifications to its policies for evaluating oil pipeline index rate changes and to the data reporting requirements reflected in page 700 of Form No. 6. As discussed below, the Commission's index ratemaking methodology has become the predominant mechanism for adjusting oil pipeline rates under the Interstate Commerce Act (ICA). Therefore, ensuring that index rate increases do not cause pipeline revenues to unreasonably depart from oil pipeline costs, and that both the Commission and oil pipeline shippers have sufficient information to assess the relationship between oil pipeline rates and costs, is essential to the Commission's implementation of its statutory obligations under the ICA. In this Advance Notice of Proposed Rulemaking (ANOPR), the Commission is considering a series of reforms to improve the Commission's and shippers' ability to ensure that oil pipeline rates are just and reasonable.

2. This ANOPR is the result of the Commission's ongoing monitoring and evaluation of the relationship between oil pipeline costs and rates. In 2015, the Liquids Shippers Group,[1] Airlines for America,[2] and the National Propane Gas Association [3] (collectively, Joint Shippers) filed a petition for rulemaking seeking additional cost information on Form No. 6, page 700.[4] In July 2015, the Commission held a technical conference discussing this proposal, including the Joint Shippers' asserted need for greater insight into oil pipelines' costs and revenues to enable shippers to challenge oil pipeline rates that may be unjust and unreasonable.

3. In addition, the Commission recently completed the 2015 Five-Year Indexing Review proceeding, which involved an assessment of the relationship between the oil pipeline Start Printed Page 76316index and industry costs.[5] Although the five-year review process addressed the calculation of the index-level on an industry-wide basis, it did not address how individual oil pipelines may adjust their rates based on the approved index.

4. However, through the Commission's ongoing monitoring of how the index affects pipeline rates, the Commission has observed that some pipelines continue to obtain additional index rate increases despite reporting on Form No. 6, page 700 revenues that significantly exceed costs. The Commission's experience with index proceedings has also indicated that our standards for evaluating shipper objections to index filings could be strengthened and clarified, to both protect against excessive rate increases and, consistent with the streamlined and simplified methodology required by Congress,[6] minimize costly and time-consuming litigation regarding pipeline rates.

5. Accordingly, in this ANOPR, the Commission proposes reforms to its review of oil pipeline index rate filings and the reporting requirements for Form No. 6, page 700 to better fulfill its statutory obligations under the ICA. First, the Commission is considering a new policy that would deny proposed index increases if (a) a pipeline's Form No. 6, page 700 revenues exceed the page 700 total cost-of-service by 15 percent for both of the prior two years or (b) the proposed index increases exceed by 5 percent the annual cost changes reported on the pipeline's most recently filed page 700.

6. Second, in response to the Joint Shippers' Petition, the Commission is also considering applying these new reforms to costs more closely associated with the proposed indexed rate than the total company-wide costs and revenues presently reported by oil pipelines on page 700. Accordingly, the Commission is considering requiring pipelines to file supplemental page 700s for (a) crude pipelines and product pipelines, (b) non-contiguous systems, and (c) major pipeline systems. The Commission also seeks comments regarding a proposed requirement that pipelines report (a) information regarding the allocations used to prepare the supplemental page 700s, and (b) separate revenues for cost-based rates (e.g. indexing), non-cost-based rates (e.g. market-based rates or settlement rates), and other jurisdictional revenues (such as penalties).

I. Background

7. The Commission regulates the rates, terms, and conditions that oil pipelines charge under the Interstate Commerce Act (ICA).[7] The ICA prohibits oil pipelines from charging rates that are “unjust and unreasonable” and permits shippers and the Commission to challenge both pre-existing and newly filed rates.[8]

8. In the Energy Policy Act of 1992 (EPAct 1992), Congress mandated that the Commission establish a simplified and generally applicable ratemaking methodology for oil pipelines and streamline procedures in oil pipeline rate proceedings.[9] In response to EPAct 1992's mandate, the Commission issued Order No. 561 creating the indexing methodology,[10] which allows oil pipelines to change their rates subject to certain ceiling levels as opposed to making cost-of-service filings to change those rates. These ceiling levels change every July 1 with an index based upon industry-wide cost changes.[11] Indexing serves as the Commission's primary oil pipeline ratemaking methodology. However, the Commission also permits oil pipelines to change their rates via (a) a traditional cost-of-service filing based upon a showing that a substantial divergence exists between the pipeline's indexed rates and the pipeline's costs, (b) market-based rates if the pipeline can demonstrate it lacks market power, and (c) settlement rates.[12]

9. At the same time it created the indexing methodology, the Commission added page 700 to Form No. 6 to serve as a preliminary screening tool to evaluate indexed rates.[13] Page 700 provides a simplified presentation of an oil pipeline's jurisdictional cost-of-service and revenues. In its present form, page 700 reflects only total company data and does not provide separate costs-of-service for different parts of a pipeline system.

10. Page 700 serves as the means for the Commission's initial evaluation of protests and complaints alleging that a pipeline's indexed rate change is “substantially in excess” of the pipeline's cost changes.[14] When a shipper files a protest against an oil pipeline's indexed rate change, the percentage comparison test has been used by the Commission to determine whether to investigate the indexed filing. The percentage comparison test compares (a) the change in the prior two years' total cost-of-service data reported on page 700 with (b) the proposed indexed rate change.[15] If the percentage comparison test differential is greater than 10 percent, the Commission has historically investigated the protested index filing via subsequent administrative law judge hearing procedures, and, depending upon the outcome of that investigation, may modify or reject the index rate change. If the differential is less than 10 percent, the Commission has generally exercised its discretion to accept the rate filing without an investigation.[16]

11. The Commission also relies upon page 700 as a preliminary screen to evaluate complaints against an indexed rate change. Whereas the percentage comparison test has served as the means for evaluating a protest to an index rate change, the Commission applies a wider range of factors to evaluate complaints.[17] These factors include the substantially exacerbate test that directs further investigation if (a) a pipeline is already “substantially over-recovering” and (b) the pipeline has filed an index increase that would “substantially exacerbate” that over-recovery. If a shipper provides reasonable grounds that a pipeline's index increase will substantially exacerbate an existing over-recovery, the Commission will set Start Printed Page 76317the matter for hearing before an administrative law judge.[18]

II. Indexing Policies

12. The Commission is contemplating changes to indexing policies for evaluating annual oil pipeline indexed filings. These changes would modify both the existing percentage comparison test and the substantially exacerbate test. Through these modifications, the Commission seeks to ensure that oil pipeline rates under the ICA are just and reasonable by reducing the likelihood that an oil pipeline's rates substantially deviate from its costs through the application of indexed rate increases. The Commission also is exploring whether and how such changes would further streamline and simplify its regulations consistent with the objectives of EPAct 1992.

13. Accordingly, the Commission is considering a two-part evaluation of index filings.[19] The Commission would use these tests to strengthen and clarify its evaluation of all indexed filings upon the filing of a protest or complaint or upon the Commission's own initiative.[20] The first part of the evaluation, the new “exacerbate” test, would deny any ceiling level increase or indexed rate increases for pipelines in which a pipeline's page 700 revenues exceed page 700 total costs by 15 percent for both of the prior two years. The second part of the evaluation, the new percentage comparison test, would deny a proposed increase to a pipeline's rate or ceiling level greater than 5 percent of the barrel-mile cost changes reported on page 700.[21] These tests would be used by the Commission to accept or reject oil pipeline indexed filings without, at least in most cases, establishing hearing procedures.[22]

14. The Commission anticipates that the new exacerbate test, which considers the relationship between an oil pipeline's revenues and its costs, will have several benefits. Under indexing, individual oil pipelines may change their rates based upon industry-wide cost changes.[23] When an oil pipeline's revenues significantly exceed costs, the pipeline still may seek and receive an additional rate increase that may further increase this gap. This is because, currently, the Commission does not typically consider the relationship between an oil pipeline's revenues and its costs when evaluating an indexed rate change. The exception, the existing substantially exacerbate test, only applies after the proposed rate increase becomes effective and a shipper files a complaint.

15. Through the new exacerbate test, shippers could raise objections to proposed rate increases when pipeline revenues already appreciably exceed costs. The contemplated 15 percent threshold is intended to preserve an indexing regime based upon industry-wide cost changes while also ensuring that the index does not cause a particular oil pipeline's rates to unreasonably depart from its costs. For example, an oil pipeline with costs corresponding to industry-wide averages and with revenues 115 percent of costs would earn a real return on equity (ROE) [24] that is appreciably higher than the real ROE the pipeline itself has identified on page 700.[25] Under these circumstances, it may be reasonable to deny additional index rate increases. However, to avoid distortions caused by one-year fluctuations in costs and revenue, the Commission only anticipates denying an index increase if the 15 percent threshold is exceeded for two consecutive years.

16. Similarly, the Commission also anticipates that the new percentage comparison test will help ensure that rates better reflect costs. By reducing the gap between an annual rate increase and a pipeline's cost changes from 10 to 5 percent, the Commission constrains the difference that can emerge in a one-year period between a pipeline's costs and its revenues.[26] However, as is the case with the existing percentage comparison test, if a pipeline's page 700 reported costs exceed its revenues, the Commission would permit the pipeline to take the full index increase because the pipeline is not recovering its costs.

17. The Commission is also considering requiring pipelines, whether or not they modify their indexed rates, to make an annual filing showing changes in their ceiling levels.[27] These ceiling levels would also be subject to challenge using the new exacerbate and percentage comparison tests. Applying these processes to the pipeline's rate ceilings, not just the rates, would limit the emergence of pipeline over-recoveries. Under the new exacerbate test, a pipeline's ceiling levels would not increase when its revenues exceed 115 percent of costs, ensuring that the pipeline would not be able to significantly raise its rates (and thus revenues) immediately after page 700 revenues fall below 115 percent of page 700 costs.[28] Likewise, by applying Start Printed Page 76318the new percentage comparison test to a pipeline's ceiling level changes (as well as to its indexed rate changes), the Commission also would limit the ability of a pipeline to carry-forward the full indexed increase to a future period when that increase significantly exceeds (i.e. more than 5 percent) the pipeline's cost changes.[29]

18. The Commission anticipates these tests can be used to simplify and streamline oil pipeline ratemaking procedures. While page 700 has been used as a “preliminary screen,” under the tests proposed here, the pipeline's own reported cost data on page 700 would serve as a sufficient basis for a decision to deny a challenged index rate filing. In such circumstances, a full hearing before an administrative law judge would not be necessary. By relying more upon the pipeline's self-reported page 700 data, the Commission could simplify and streamline the process for evaluating indexed rate changes. To the extent that commenters believe there may be circumstances in which the new exacerbate test and the revised percentage comparison tests when applied to page 700 (or the supplemental page 700s described below) would not provide a reasonable basis for accepting or rejecting an indexed filing, commenters should (a) identify those circumstances and (b) specifically discuss how those circumstances could be addressed for evaluating indexed rate changes in a simplified and streamlined ratemaking process.

19. Along similar lines, the Commission anticipates that these modifications would streamline and simplify Commission policies by establishing clearer standards. For example, under the new exacerbate test, the Commission would be identifying the specific threshold for what constitutes a “substantial over-recovery.” Further, when the Commission sets an indexed rate filing for hearing based upon either the percentage comparison test or the substantially exacerbate test, there is limited precedent providing guidance regarding the parameters and scope of such a hearing subject to a simplified ratemaking methodology.[30] This lack of clarity creates complexity and uncertainty for both shippers and pipelines. By accepting and rejecting indexed filings based upon the proposed new exacerbate and percentage comparison tests, the Commission seeks to establish a clearer policy consistent with the objective of a simplified and streamlined ratemaking process.

20. Whether relying upon the existing page 700 or the supplemental page 700s, the Commission expects that these new tests would serve as the primary mechanism for evaluating oil pipeline indexed rate changes.[31] The Commission anticipates that these new policies for evaluating indexed filings would both (a) ensure that index rate increases do not cause pipeline revenues to substantially deviate from costs and (b) streamline and simplify the Commission's ratemaking methodologies.

III. Modifications to Page 700

21. The Commission has preliminarily concluded that additional reporting requirements may enhance the ability of shippers and the Commission to monitor oil pipeline rates. First, the Commission is considering a requirement that pipelines file supplemental page 700s for (a) crude pipelines and product pipeline systems, (b) non-contiguous systems, and (c) certain major pipeline systems. These changes would complement the proposed new exacerbate and percentage comparison tests. Using the supplemental page 700s, the Commission could evaluate indexed rate changes based upon costs and revenues more closely related (and thus more relevant) to the proposed indexed rate change.[32]

22. Second, the Commission is considering requiring pipelines on page 700 and the supplemental page 700s to report additional information regarding (a) cost allocations used on the supplemental page 700s and (b) separate revenues for cost-based rates (e.g., indexing), non-cost-based rates (e.g., market-based rates), and other jurisdictional revenues (such as penalties).

A. Background

The Commission's reevaluation of page 700 originated with the Joint Shippers' petition for rulemaking. In the petition, the Joint Shippers requested that the Commission require pipelines to disaggregate the total company data reported on page 700 and to file supplemental page 700s with summary costs-of-service for (a) crude and product systems and (b) for each “rate design” segment. The Joint Shippers' proposal also requested that all interested parties be given access to the work papers used to prepare page 700. A technical conference held July 30, 2015, discussed the Joint Shippers' petition. The Commission provided the opportunity for initial comments due September 25, 2015 and reply comments due October 30, 2015. At the technical conference and in subsequent comments, the Association of Oil Pipelines (AOPL) opposed the proposal as unduly burdensome and inconsistent with the Commission's indexing ratemaking regime. In addition to the comments from AOPL the Commission also received nine separate initial comments from pipeline entities opposing the petition.[33] The Joint Commenters,[34] Liquids Shippers Group, the Canadian Association of Petroleum Producers,[35] and Tesoro Refining and Marketing LLC filed initial comments supporting the proposal. On October 30, Start Printed Page 763192015, AOPL and SFPP, L.P., filed reply comments expressing continued opposition to the petition and the Joint Commenters and the Liquids Shippers Group filed reply comments in further support of the petition.

23. In its reply comments, AOPL advanced a limited alternative proposal to the petition that would require pipelines to report carrier property data shown on Form No. 6, pages 212-213 and accrued depreciation data shown on Form No. 6, page 216 separately for crude oil and products.[36] Using this data, AOPL stated shippers could estimate costs by crude and products pipeline systems. In the supplemental reply comments filed November 23, 2015, Joint Commenters argued AOPL's counterproposal did not provide adequate information for shippers to meaningfully evaluate the reasonableness of rates.[37] On December 8, 2015, AOPL filed a response to the Joint Commenters Supplemental Reply Comments.

B. Supplemental Page 700s

1. Commission Proposal

24. The Commission's preliminary assessment indicates that providing supplemental page 700s for different parts of a pipeline system may enhance the Commission's and shippers' ability to evaluate a pipeline's indexed rates.

25. For some pipelines, the total company data on page 700 consolidates costs and revenues from several different assets, including (a) pipeline systems that move crude oil as opposed to petroleum products, (b) non-contiguous systems that use geographically separate assets, and (c) major pipeline systems that extend at least 250 miles and serve fundamentally different markets. The costs associated with providing service on one of these systems may be fundamentally different from the costs associated with providing service on other parts of the total company pipeline system. Accordingly, these supplemental page 700s would be useful both in the evaluation of index filings (as discussed above) and for cost-of-service challenges to oil pipeline rates. When a pipeline seeks an indexed increase to a particular rate, shippers and the Commission could use the supplemental page 700s to compare the rate change with costs that are more closely associated with that particular rate.

26. Accordingly, as discussed below, the Commission is considering requiring pipelines to file supplemental page 700s for crude oil systems (labeled 700c) and petroleum product systems (labeled 700p). Within each of these crude and product systems, the Commission is considering a further requirement that pipelines provide a supplemental page 700 for (a) non-contiguous (geographically separate) pipeline systems [38] and (b) major pipeline systems. Major pipeline systems would consist of large pipeline systems (at least over 250 miles) that serve markets (either origin or destination) different from the remainder of the pipeline's system.[39] Major pipeline systems would also include separate pipeline systems (even those below the 250-mile threshold) established by a final Commission order in a litigated rate case. The supplemental page 700s for non-contiguous and major pipeline systems would be labeled 700c1, 700c2, etc., for crude systems, and 700p1, 700p2, etc., for product systems.[40]

27. The Commission anticipates that these supplemental page 700s would allow index rate changes to be evaluated using data that is more relevant to a particular shipper's rates than the currently reported company-wide data. These criteria identify pipeline systems associated with (a) separate transportation movements and (b) costs due to the use of different assets.

28. The Commission expects that the benefits described above will outweigh the accounting burden for disaggregating the cost data on these supplemental page 700s. For crude and product systems, pipelines are already required to disaggregate significant data on the Form No. 6. For non-contiguous pipelines, geographically separate systems are also more likely to be recorded separately on a company's books and records.[41] Similarly, 250-mile major pipeline systems are likely to be of sufficient significance that the pipeline separately tracks the costs and revenues associated with such a large part of its business. Nonetheless, to the extent that a pipeline's existing books and records do not allow for the pipeline to directly assign certain costs that would be required to be reported on the supplemental page 700s, the Commission, as discussed below, is considering allowing for certain reasonable allocations and estimates using the available data.

29. The Commission does not presently intend to pursue additional segmentation of page 700, such as the “rate design” segments proposed in the Joint Shippers' petition. Indexing does not require an exact correlation between a pipeline's costs and rates,[42] and, given that regulatory scheme, we believe that the changes proposed above will provide sufficient transparency to allow the Commission and shippers to monitor pipelines' costs and revenues. The Commission has previously relied upon the total company costs reported on page 700, and we believe the more specific supplemental page 700s identified above will be appropriate to be used in future applications of the index.

30. Moreover, the Commission is concerned about the application of the Joint Shippers' proposal on an industry-wide basis. Most pipelines have never made a filing with the Commission identifying their rate design segments, and Commission precedent provides limited guidance for identifying rate design segments.[43] Rate design segmentation of page 700 would likely insert into the Commission's “simplified” indexing methodology complex, fact-specific disputes regarding the appropriate rate design Start Printed Page 76320segmentation.[44] Further, the Joint Shippers' alternate proposal to define rate design segments using definition 32(a) from the Uniform System of Accounts provides little clarity because this definition has historically served a separate accounting purpose and has never previously been applied to identify rate design segments.[45]

31. The comments filed in Docket No. RM15-19-000 demonstrate our concerns. As an initial matter, different shipper comments supporting the segmentation proposal identify conflicting lists of pipelines that “could” have different rate design segments.[46] Moreover, to identify these segments, the Joint Shippers used potentially inapplicable criteria such as “undivided joint interest” [47] and separate “tariff listings” [48] that, in addition to being potentially over-inclusive, failed to identify SFPP, L.P., a non-contiguous pipeline that has repeatedly been treated as operating separate segments in Commission rate cases.[49] In addition, the rate design segments identified by shippers include relatively insignificant assets, such as small laterals.[50] The burden associated with segmentation is not a one-time burden, as pipeline systems change over time and pipelines will need to re-evaluate their rate design segments in future years. Recent litigation before the Commission further demonstrates the burdens imposed by a fact-specific inquiry into a pipeline's segmentation.[51] Given the Commission's indexing ratemaking regime and our determination that alternative reforms to page 700 will provide sufficient transparency to assist the Commission and shippers, the Commission currently does not intend to pursue the Joint Shippers' proposed reporting requirement.

C. Additional Reporting Requirements on Page 700

32. The Commission is also considering requiring pipelines to report additional data on the page 700 and supplemental page 700s. First, in order to facilitate the creation of the supplemental page 700s above, the Commission is considering requiring pipelines to explain the allocation of costs between the different supplemental page 700s. Second, the Commission is considering requiring all pipelines to report separate revenues and throughput for cost-based transportation rates (resulting from indexing and cost-of-service), non-cost-based transportation rates (resulting from settlement rates and market-based rates), and other jurisdictional revenues (such as penalties).

1. Cost Allocation Data

33. The Commission is contemplating reporting requirements involving the cost allocation methodologies used to derive the system-specific data reported on the supplemental page 700s. As discussed below, the Commission recognizes pipeline arguments that it may be difficult or costly for pipelines to directly assign certain costs to the system-specific supplemental page 700s. Thus, the Commission is considering whether to permit pipelines to use reasonable methodologies for allocating those costs. However, to ensure transparency, the Commission is considering also requiring pipelines to provide information regarding these allocations on page 700. This information would allow the Commission and other interested parties to observe (a) how these allocations are affecting the supplemental page 700s' costs-of-service and (b) any changes in direct assignment or allocation practices between annual page 700 filings.[52]

34. Page 700 includes ratemaking information that, unlike typical accounting data, pipelines may not be able to cost-effectively determine on a segmented basis. For example, the Opinion No. 154-B trended original cost rate base [53] (page 700, line 5d) includes (a) the original cost of the rate base (page 700, line 5a), (b) a Starting Rate Base Write-Up developed in 1983 to transition from a prior ratemaking methodology to trended original cost ratemaking (page 700, line 5b), and (c) Net Deferred Earnings, which consists of Start Printed Page 76321the accumulations since 1983 of the inflationary component of a pipeline's annual return (page 700, line 5c).[54] Unlike typical accounting data, absent a cost-of-service rate case (which most oil pipelines have not experienced since 1983), a pipeline may have had no reason to maintain or calculate this data other than on the company-wide basis for page 700. Given that an exact accounting of the Starting Rate Base Write-Up and Deferred Earnings would require data from 1983 to the present,[55] obtaining this data may be impracticable.

35. Accordingly, to the extent the Opinion No. 154-B rate base information is not available in company records, the Commission would permit pipelines to perform a one-time allocation of these costs for preparing the supplemental page 700s. Reasonable allocations of this data should not significantly reduce the usefulness of the supplemental page 700 data. The Deferred Earnings and Starting Rate Base Write-Up are a relatively small part of an overall cost-of-service,[56] and thus reasonable allocations should not undermine the overall accuracy of the total cost-of-service that is used for evaluating indexed rates. Moreover, once this one-time allocation of these Opinion No. 154-B rate base costs establishes a base-line, future allocations should be limited.[57]

36. The Commission would also permit other allocations where appropriate. Currently, when the pipeline's business records do not allow direct cost assignment, pipelines filing page 700s use Commission-approved cost allocation methodologies for (a) allocating parent company overhead to the pipeline filing page 700 and (b) identifying the jurisdictional costs reported on page 700 as opposed to the non-jurisdictional costs. To the extent necessary, the pipelines may use reasonable methodologies for allocating costs [58] between the various systems reported on the proposed supplemental page 700s. The Commission anticipates that these methodologies will generally stay consistent over time. However, the Commission recognizes that, in some circumstances, it may be appropriate for a pipeline to further refine its allocation methodologies. The Commission also does not expect pipelines to make major or high cost modifications to accounting systems or business processes solely for the purpose of filing the supplemental page 700s.

37. The Commission, however, also seeks to ensure transparency regarding the costs allocated among the supplemental page 700s. The choice and application of cost allocation methodologies involves judgment that, to some degree, may be subjective.[59] The Commission and the public would also benefit from information regarding the amount of costs that pipelines are allocating as opposed to directly assigning. In order to ensure transparency and to monitor pipeline's allocation decisions, the Commission is considering requiring additional information on page 700 in order to differentiate between directly assigned and allocated costs and to briefly describe the allocation methodology.

38. Thus, for certain line items on page 700 oil pipelines would be required to report (a) directly assigned costs and (b) allocated costs.[60] The directly assigned costs would be those costs that have been assigned to a specific system based upon cost centers and location codes. For the allocated costs, the pipeline would include a footnote explaining the methodology used to allocate those costs, including (a) Kansas-Nebraska methodology, (b) volumetric method, (c) gross plant, or (d) other methodologies.[61]

39. Second, in order to facilitate understanding of these allocations, on both page 700 and the supplemental page 700s, the Commission is considering requiring additional data involving rate base.[62] Specifically, this approach would add to line 5a, Rate Base—original cost; line 5a1—Total Carrier Property In Service (Gross Plant); line 5a2—Net Carrier Property In Service (Net Plant); line 5a3—ADIT; and line 5a4—Total Working Capital. Gross and net plant could be important for understanding how costs are being allocated. For example, this data may provide a means for allocating the Opinion No. 154-B cost data.

40. By permitting oil pipelines to use estimates and cost allocations for certain costs, the Commission would seek to reduce the compliance costs associated with the supplemental page 700s. However, the use of allocations would be balanced by the additional reporting requirements that would enable the Commission and shippers to monitor both the level of allocated costs and, in general terms, how those costs were allocated.

2. Revenue, Barrel and Barrel Mile Data

41. The Commission is also considering requiring pipelines to disaggregate page 700 revenue, barrel, and barrel-mile data associated with (a) cost-based rates (resulting from indexing and cost-of-service), (b) non-cost-based rates (resulting from settlement rates Start Printed Page 76322and market-based rates), and (c) other jurisdictional revenues (such as penalties).

42. When page 700 was created following EPAct 1992, most oil pipeline revenues resulted from rates subject to cost-based regulation. Therefore, comparing total revenue to total costs served as an effective preliminary means to determine whether to challenge a pipeline's cost-based rates. However, in recent years, an increasing percentage of pipelines are using settlement rates (including negotiated rates associated with new construction). Also, at the same time the Commission created page 700, the Commission formalized its market-based rates policy in Order No. 572.[63] The revenue derived from these non-cost-based rates may substantially deviate from a pipeline's cost-of-service, but still be just and reasonable.[64]

43. Separating the cost-based and non-cost-based revenue could help the Commission and pipeline shippers to assess, on a preliminary basis, whether a gap between total company costs and revenues likely results from cost-based rates (which could be challenged on a cost-of-service basis) or from non-cost-based rates (which could not be challenged on a cost basis). Also, because a pipeline must know the rate to charge a shipper seeking service, this revenue data should be relatively simple for the pipeline to identify and to track.

44. Certain limitations apply to this data. Different revenue sources may apply to different parts of the pipeline with different costs.[65] As a result of this mismatch, the Commission does not intend to use the disaggregated cost-based revenues in the indexing screens described above. However, this additional information would nonetheless enable the Commission and the industry to evaluate the relative effect of the Commission's different ratemaking methodologies. It could also provide an initial assessment for shippers contemplating a cost-of-service complaint against a pipeline's rates.[66]

3. Work Papers

45. Based on our consideration of the record in Docket No. RM15-19, and our proposed revisions to page 700 included in this ANOPR, we do not propose requiring pipelines to make the work papers used to prepare page 700 available to all interested parties as requested by the Joint Shippers' petition.

46. As described earlier in the ANOPR, the Commission is proposing to significantly revise pipeline reporting requirements for page 700. Page 700 data filed by the pipelines is under oath and subject to Commission audit. The current data on page 700 allows a shipper to compare (a) a pipeline's revenues to its total cost-of-service and (b) changes to a pipeline's total cost-of-service. Under both the Commission's current policy and the policy changes proposed above, this is the data directly used to evaluate challenged index filings. Page 700 also provides significant context for these total costs, including several major cost-of-service subcomponents. By requiring additional information on page 700 and the supplemental page 700s regarding (a) rate base (proposed lines 5a1-5a4), (b) the cost allocations, and (c) revenues, the Commission is providing additional context for the data on page 700.[67] We believe that this additional information provides sufficient information to allow the Commission and shippers to evaluate index findings and conduct a preliminary evaluation of a pipeline's rates prior to bringing a cost-of-service challenge. However, we invite comments on the sufficiency of this additional information in evaluating index filings and conducting preliminary evaluations of a pipeline's rates prior to bringing a cost-of-service challenge.

47. In support of their proposal, the Joint Shippers emphasize that the Commission currently has access to pipeline work papers. While true, we believe that, on balance, mandating disclosure of work papers is not necessary to provide shippers with sufficient information when considering challenges to pipelines' proposed or existing rates. In particular, we note that the dissemination of this data to shippers raises potential confidentiality concerns that do not exist when the Commission reviews the work papers. These issues include (a) shipper information protected by section 15(13) of the ICA, which prohibits disclosure of an individual shipper's movements and (b) the pipeline's competitive business information. On balance, we find that the general disclosure of this information, even subject to confidentiality agreements, is not appropriate at this time.

IV. Burden

48. The Commission invites commenters to also address the potential cost of the proposals being considered in this ANOPR. Comments could include an estimate of both the one-time implementation costs and the ongoing compliance costs. The Commission will provide a burden estimate in any future notice of proposed rulemaking.

V. Comment Procedures

49. The Commission invites interested persons to submit comments on the matters and issues presented in this notice to be adopted. Initial comments are due December 19, 2016 and reply comments are due January 31, 2017. Comments must refer to Docket No. RM17-1-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments.

50. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's Web site at The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

51. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Start Printed Page 76323Secretary of the Commission, 888 First Street NE., Washington, DC 20426.

52. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

VI. Document Availability

53. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission's Home Page ( and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426.

54. From the Commission's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

55. User assistance is available for eLibrary and the Commission's Web site during normal business hours from the Commission's Online Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. Email the Public Reference Room at

Start Signature

By direction of the Commission.

Issued: October 20, 2016.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

End Signature End Supplemental Information


1.  Liquids Shippers Group consists of the following crude oil or natural gas liquids producers: Anadarko Energy Services Company, Apache Corporation, Cenovus Energy Marketing Services Ltd., ConocoPhillips Company, Devon Gas Services LP, Encana Marketing (USA) Inc., Marathon Oil Company, Murphy Exploration and Production Company USA, Noble Energy Inc., Pioneer Natural Resources USA Inc., and Statoil Marketing and Trading (US) Inc.

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2.  Airlines for America is a trade association representing cargo and passenger airlines, including Alaska Airlines, Inc., American Airlines Group (American Airlines and US Airways), Atlas Air, Inc., Delta Air Lines, Inc., Federal Express Corporation, Hawaiian Airlines, JetBlue Airways Corp., Southwest Airlines Co., United Continental Holdings, Inc., and United Parcel Service Co.

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3.  The National Propane Gas Association is a national trade association of the propane industry with a membership of approximately 3,000 companies, including 38 affiliated state and regional associations representing members in all 50 states.

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4.  Petition for Rulemaking, Docket No. RM15-19-000 (filed April 20, 2015) (Petition).

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5.  Five Year Review of the Oil Pipeline Index, 153 FERC ¶ 61,312 (2015).

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6.  See infra P 8.

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7.  49 App. U.S.C. 1 et seq. (1988).

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8.  49 App. U.S.C. 13(1), 15(1), and 15(7).

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9.  Energy Policy Act of 1992, Public Law 102-486 Sec. 1803(b), 106 Stat. 3010 (Oct. 24, 1992).

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10.  Revisions to Oil Pipeline Regulations pursuant to Energy Policy Act of 1992, Order No. 561, FERC Stats. & Regs, ¶ 30,985, at 30,940 (1993), order on reh'g and clarification, Order No. 561-A, FERC Stats. & Regs., ¶ 31,000 (1994), aff'd sub nom. Ass'n of Oil Pipe Lines v. FERC, 83 F.3d 1424 (D.C. Cir. 1996) (AOPL).

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11.  Pursuant to the Commission's indexing methodology, oil pipelines change their rate ceiling levels effective every July 1 by “multiplying the previous index year's ceiling level by the most recent index published by the Commission.” 18 CFR 342.3(d)(1) (2016). Currently, the index level is based upon the Producer's Price Index for Finished Goods plus 1.23, which was based upon the relationship between PPI-FG and oil pipeline cost changes during the 2009-2014 period. The index level is reviewed every five-years. See Five-Year Review of the Oil Pipeline Index, 153 FERC ¶ 61,312 (2015).

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13.  Cost-of-Service Reporting and Filing Requirements for Oil Pipelines, Order No. 571, FERC Stats. & Regs., ¶ 31,006 (1994), order on reh'g and clarification, Order No. 571-A, FERC Stats. & Regs., ¶ 31,012 (1994), aff'd sub nom. All jurisdictional pipelines are required to file page 700, including pipelines exempt from filing the full Form 6. 18 CFR 357.2(a)(2) and (a)(3) (2016).

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15.  Calnev Pipe Line L.L.C., 130 FERC ¶ 61,082, at PP 10-11 (2010) (Calnev).

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16.  SFPP, L.P., 143 FERC ¶ 61,141, at P 6 (2013).

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17.  Calnev, 130 FERC ¶ 61,082 at P 11. The Commission has explained that it will consider additional factors in a complaint because it has more time to evaluate complaints and the complainant must carry the burden of proof. BP West Coast Products LLC v. SFPP, L.P., 122 FERC ¶ 61,141, at PP 6-7 (2007).

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18.  BP West Coast Products LLC v. SFPP, L.P., 122 FERC ¶ 61,129 (2008).

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19.  The Commission does not propose to change its policies for evaluating index rate decreases. If the index causes a pipeline's rate ceiling to decline, then the pipeline must adjust its rates so that they remain at or below the reduced rate ceiling. 18 CFR 342.3(e) (2016).

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20.  Consistent with the policy articulated in Order No. 561, the Commission anticipates continued reliance upon affected shippers to bring challenges that apply the standards contemplated by this ANOPR to indexed rate changes. Order No. 561, FERC Stats. & Regs., ¶ 30,985 at 30,967. However, the Commission retains the authority to investigate on its own initiative oil pipeline rates, including indexed rates, under sections 13 and 15 of the ICA.

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21.  The Commission currently uses costs, not costs per barrel-mile, when applying the percentage comparison test to oil pipeline cost changes. However, total cost levels can fluctuate due to changing throughput even if the expenses of moving a particular barrel remain the same. The Commission has concluded that cost per barrel-mile (Line 9/Line 12) may provide a more accurate measure of a pipeline's cost changes.

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22.  In other words, if a pipeline's index filing satisfied both tests, it would generally be accepted. Likewise, if the index filing failed either the exacerbate test or the percentage comparison test, it would generally be rejected.

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23.  Using an industry-wide index both simplifies the ratemaking procedures by avoiding consideration of a particular pipeline's costs and rewards efficient companies that control costs. “Indexing fosters efficiency by severing the linkage under traditional cost-of-service ratemaking between . . . rate changes and . . . costs. This provides the pipeline with the incentive to cut costs aggressively, since . . . it may retain a portion of the savings it generates.” See Order No. 561, FERC Stats. & Regs., ¶ 30,985 at 30,948 n.37.

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24.  The real ROE is the nominal or total ROE less the inflationary component of ROE.

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25.  When a pipeline reports revenues that are 115 percent of page 700 total cost-of-service, approximately one-third of these additional revenues represent income tax liabilities and the remaining two-thirds are additional equity earnings for the pipeline. Accordingly, for a hypothetical pipeline reporting the industry-wide average page 700 return on equity (page 700, line 7b) of approximately 18.3 percent of its total costs (page 700, line 9), the additional revenues would translate to an increase in equity return of 55 percent (i.e. 2/3 * 15 percent/18.3 percent). If the pipeline incorporated the industry-wide average ROE of 10.4 percent in its page 700 cost-of-service (page 700, line 6d), such a pipeline would actually be recovering a 16.1 percent real ROE (10.4 percent + 10.4 percent * 55 percent). The Commission calculated the industry-wide averages in this footnote based upon the publicly available page 700 data filed by oil pipelines.

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26.  Using the 10 percent threshold, a pipeline with costs annually declining by 5 percent and 4.9 percent of annual indexed rate increases could have revenues that exceed costs by roughly 20 percent after two years and 30 percent after three years. Applying that same hypothetical but using the 5 percent threshold, the revenues would only exceed costs by 10 percent after two years and around 15 percent after three years.

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27.  As explained, supra P 8, indexing allows oil pipelines to change their rates subject to certain ceiling levels. These ceiling levels change every July 1 with an index based upon industry-wide cost changes. When a pipeline's ceiling levels change, the pipeline is not currently obligated to make a filing with the Commission. Pipelines are currently only obligated to make a filing with the Commission if they change their rates pursuant to the changing ceiling levels.

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28.  In other words, the change in the ceiling increase would be limited to a 5 percent difference from the pipeline's cost change. For example, if the index for 2018 is 3 percent, and the pipeline's cost change is −3 percent, the pipeline's ceiling level could not increase by 3 percent because this would fail the percentage comparison test because 6 [3−(−3)] is more than 5. Rather, in this hypothetical example, the ceiling level could only change by 2 percent [2−(−3) = 5]. This 2 percent increase to the ceiling level would carry forward whether or not the pipeline raised its rates up to the ceiling.

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29.  Currently, Commission policy allows a pipeline to file a partial index rate increase leading to a percentage comparison test of 9.9 percent while the pipeline's ceiling rate still increases by the full index. The pipeline can make a filing with the Commission to increase its rates up to the ceiling level in a subsequent year.

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30.  Consistent with the intent of indexing to create a simplified ratemaking methodology, the investigation into an indexed rate increase should not require the parties to fully litigate a cost-of-service rate case.

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31.  Because page 700 is critical to the Commission's ability to monitor oil pipeline rates, the Commission emphasizes that pipelines must comply with the current requirement to file the Form No. 6, including the page 700, by April 18 of each year. Although waivers may still be granted in limited circumstances, the Commission must be able to evaluate the indexed rates before they become effective on July 1 of each year. Failure to timely file the Form No. 6 could delay the effective date of a pipeline's proposed indexed increase or, potentially, lead to the outright rejection of the requested increase.

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32.  Shippers could also use the supplemental page 700 as the basis for initiating a cost-of-service complaint against a pipeline's rates. Consistent with the mandate for a simplified ratemaking methodology in EPAct 1992, the Commission created indexing to avoid cost-of-service litigation. However, shippers may still pursue cost-of-service claims if a pipeline's indexed rates substantially diverged from a pipeline's costs. Arco v. Calnev Pipe Line, L.L.C., 97 FERC ¶ 61,057, at 61,311 (2001) (citing Order No. 561, FERC Stats. & Regs., ¶ 30,985 at 30,955).

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33.  The Commission received comments from Explorer Pipeline Company, Magellan Midstream Partners, L.P., Marathon Pipe Line LLC, Shell Pipeline Company LP, Plains Pipeline, L.P., SFPP, L.P., Buckeye Pipe Line Company, L.P., jointly NuStar Logistics, L.P. and NuStar Pipeline Operating Partnership, L.P., and, jointly, Enterprise Products Partners L.P. and its operating subsidiaries Enterprise TE Products Pipeline Company LLC and Mid-America Pipeline Company, LLC.

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34.  Joint Commenters include Airlines for America, National Propane Gas Association, and Valero Marketing and Supply Company.

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35.  The Canadian Association of Petroleum Producers represents companies that develop and produce natural gas and crude oil throughout Canada.

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36.  AOPL Reply Comments, Docket No. RM15-19-000, at 60.

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37.  Joint Commenters Supplemental Reply Comments, Docket No. RM15-19-000, at 18.

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38.  For example, if one pipeline system goes from California to Nevada and another pipeline system goes from Texas to Arizona.

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39.  A major pipeline system would include one branch of a “V” where different parts of the total company system share a similar origin but where one 250-mile system serves destinations to the northwest and another part travels to destinations to the northeast. Laterals, different divisions of an integrated and interconnected reticulated pipeline, different divisions of a straight-line pipeline, and granular rate segments are not intended to be a major pipeline system within the Commission's contemplated definition.

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40.  By definition, if a pipeline has one major pipeline system labeled 700c1 which extends over 250 miles, it must also file a supplemental page 700c2 for the remainder of its crude system.

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41.  Pipelines typically record their costs using cost centers and location codes. It seems reasonable that in most cases these data should be sufficiently precise to associate particular costs with the major pipeline system identified above.

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42.  As the United States Court of Appeals for the District of Columbia Circuit has explained, requiring an individualized cost-of-service evaluation for each pipeline would be inconsistent with the simplification mandated by EPAct 1992. AOPL v. FERC, 281 F.3d 239, 244 (D.C. Cir. 2002). Indexing achieves simplification by using an industry-wide index as opposed to relying upon a detailed examination of each pipeline's particular costs. The Commission only considers a pipeline's particular cost changes if the index rate change is in “substantial excess” of the pipeline's costs or there is a substantial divergence between a pipeline's rates and the costs associated with those rates.

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43.  A pipeline would only need to identify its rate design segments if it litigated a cost-of-service rate case. Because pipelines primarily use indexing to change their rates, such cost-of-service cases are rare. The Commission has only required one pipeline, SFPP, to use segmented data in a cost-of-service case. SFPP, LP, 86 FERC ¶ 61,022, at 61,080 (1999). There, the Commission made a series of fact-specific holdings to conclude that SFPP's south system consisted of two rate design segments, one travelling from Texas to Phoenix, Arizona, and another from California to Phoenix, Arizona.

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44.  How a pipeline defines its segments could fundamentally affect which rates are eligible for an indexed increase based upon the supplemental page 700s.

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45.  Rather, this definition applies to the accounting rules for treatment of the purchase and sale of an asset. Specifically, based upon definition 32(a), the sale or disposal of a “segment of a business” must be accounted for as part of “discontinued operations” and not included among the gains and losses associated with pipeline's continuing operations. See 18 CFR pt. 352, Instruction 1-6(c) and Account No. 676 (2016) (“Gain (loss) on disposal of discontinued segments”). The Commission's considerations when applying this accounting definition may differ significantly from considerations used to identify separate segments in a rate case.

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46.  Compare Tesoro Refining and Marketing LLC Initial Comment, Docket No. RM15-19-000, Appendix with Joint Shippers Initial Comment, Docket No. RM15-19-000, at 38-39; Attachment 2, Affidavit of Michael R. Tolleth, Docket No. RM15-19-000, at 9 & Liquid Shippers Group Initial Comments, Docket No. RM15-19-000, at 30.

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47.  The Joint Shippers state that undivided joint interests pipelines indicate the existence of separate rate design segments because these systems “generally have tariffs for each of the owners and may be geographically disconnected from other segments.” Joint Shippers Initial Comment, Attachment 2, Affidavit of Michael R. Tolleth, Docket No. RM15-19-000, at 12. However, because pipelines can structure their own tariffs, it is not clear whether merely having a separate tariff justifies a separate rate design system. Moreover, it is not clear that undivided joint systems are necessarily geographically separate. For example, the “Maumee System” is a crude oil pipeline that runs from Lima, OH, and to Samaria, MI. Mid-Valley Pipeline Company (Mid-Valley) and Hardin Street Holdings (Hardin) jointly own the “Maumee System.” Including Maumee, Mid-Valley's System extends continuously from northeast Texas to Samaria, Michigan, with receipts a several points on the southern portion of its system and delivery points all along its system, including four points on the Maumee System. In any event, to the extent an undivided joint interest pipeline is geographically separate, it would be addressed by the Commission's definition above.

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48.  Oil pipelines have discretion with the structuring of their tariff, and how the tariff is structured does not necessarily establish whether or not separate rate design segments exist.

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49.  See Affidavit of Michael R. Tolleth, Figure 1, Docket No. RM15-19-000, page 9.

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50.  The shippers' proposal exempts pipelines that report total company revenues less than $10 million for each of the three previous years. However, it does not address small segments within larger total systems. For instance, the shippers' filings identify a 12-mile lateral on the Seminole pipeline as potentially requiring a separate page 700. Compare AOPL Reply Comments, Docket No. RM15-19-000, at 26-27 with Joint Shippers Supplemental Reply Comments, Docket No. RM15-19-000, at 8-9.

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51.  These disputes have involved issues very specific to the operations of a particular pipeline system, such as (a) whether a pipeline, which was effectively a single pipe moving from the Gulf of Mexico to the northeastern United States, should be divided into two separate rate design systems (Joint Shippers Initial Comment, Attachment 1, Affidavit of Daniel S. Arthur, Docket No. RM15-19-000, at 28 and Appendix O) (discussing TE Enterprise Products, Docket No. IS12-203-000); (b) whether a pipeline's extension into Long Island, NY, should be treated separately from its much larger Eastern System on the basis of the different product moved, different pipeline vintages, different operational requirements and other factors (Joint Shippers Initial Comment, Attachment 1, Affidavit of Daniel S. Arthur, Docket No. RM15-19-000, Appendix E at 2) (discussing Buckeye Pipeline, Docket No. OR12-28-000); and (c) although not objecting to the segmentation in that particular case, questioning whether one of a pipeline's three systems should be divided further to account for different lines that move different products and serve different shippers (National Propane Group, et al, Initial Brief, Docket Nos. IS05-216-000, et al., at 13-14 (filed February 7, 2008) (discussing Mid-America Pipeline Company, LLC's Northern System). The oil pipeline cost-of-service cases involving rate design segmentation disputes have generally settled before the Commission issues a precedential order. However, they illustrate the burden that would be imposed by requiring every pipeline that files a page 700 to assess its system in this manner.

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52.  As provided by the current instructions on page 700, a pipeline must explain any change in its application of the Opinion No. 154-B cost-of-service methodology from the prior year.

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53.  The Commission's cost-of-service methodology was established in Opinion No. 154-B. Williams Pipe Line Co., Opinion No. 154-B, 31 FERC ¶ 61,377, order on reh'g, Opinion No. 154-C, 33 FERC ¶ 61,327 (1985). When the Commission established indexing and page 700, the Commission determined that it would continue to use the Opinion No. 154-B methodology to measure pipeline costs for evaluating whether a pipeline's indexed rate changes were in substantial excess of the pipeline's rate changes.

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54.  Under the Opinion No. 154-B trended original cost ratemaking, the inflationary component of the nominal return is placed in deferred earnings and recovered as a part of rate base in future years. See Opinion No. 154-B, 31 FERC ¶ 61,377. See, e.g., BP West Coast Prods., LLC v. FERC, 374 F.3d 1263, 1282-83 (D.C. Cir. 2004).

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55.  To properly allocate Starting Rate Base Write-Up, data may be needed dating back to the initial service date of the asset in question.

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56.  The Commission evaluated the role of deferred earnings as a percentage of the cost of service for each pipeline filing a 2015 page 700. The Commission calculated the percentage of deferred earnings of the total cost-of-service as follows:

Deferred Earnings = Accumulated Net Deferred Earnings, line 5c * Real Cost of Stockholders' Equity, line 6d

Taxes on Deferred Earnings = Accumulated Net Deferred Earnings, line 5c * Adjusted Capital Structure Ratio for Stockholders' Equity, line 6b * Real Cost of

Stockholders' Equity, line 6d * (Composite Tax Rate, line 8a/(1-Composite Tax Rate, line 8a))

Deferred Earnings as a Percent of Cost of Service = (Deferred Earnings + Taxes on Deferred Earnings)/Total Cost of Service, line 9.

Using this formula, deferred earnings accounted for 6.71 percent of the median pipeline's cost of service, 3.29 percent for the pipeline at the 25th percentile and 9.44 percent for the pipeline at the 75th percentile. The industry-wide mean was 6.71 percent. Because the starting rate base write-up (line 5b) has been depreciated since 1984, it is either fully depreciated or quite small on most pipelines.

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57.  In other words, once a pipeline establishes the base-line net deferred earnings for each of its supplemental page 700s, the pipeline can in subsequent years (a) amortize the base-line level established for each supplemental page 700 and (b) add future deferred earnings to the appropriate supplemental page 700. There may, however, be some further adjustments needed if a pipeline subsequently sells or acquires pre-existing assets which have accrued deferred earnings.

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58.  These allocated costs could include items such as shared assets, shared services, and overhead costs where direct assignment may sometimes be very difficult.

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59.  The Commission has established allocation methodologies that are used for ratemaking purposes. These include the Massachusetts Formula, the Kansas-Nebraska methodology, and volumetric allocations.

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60.  The requirement to break-out directly assigned and allocated costs would be added to line 1 (Operating and Maintenance Expenses), line 2 (Depreciation Expense), line 3 (AFUDC Depreciation), line 4 (Amortization of Deferred Earnings), and proposed lines 5a1-5a4 (Trended Original Cost Rate Base). This requirement would apply to all supplemental page 700s.

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61.  For example, on page 700c for crude pipeline systems, below line 1 “Operating and Maintenance Expenses,” this proposal would add Line 1a “Directly Assigned O&M Expenses,” and line 1b “Allocated O&M Expenses.” In a footnote, the pipeline could explain, “These costs were allocated using the KN Method.”

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62.  This information would be used primarily to understand the cost allocations to the different systems as reported on the supplemental page 700s. Although the Commission does not anticipate that all pipelines would be required to file the supplemental page 700s, the Commission is considering requiring all pipelines to report this information on page 700. The data would help the Commission understand a pipeline's capital costs, and this company-wide data should already be contained within the work papers used to prepare the page 700.

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63.  Prior to Order No. 572, the Commission allowed market-based rates on an experimental basis. See Buckeye Pipe Line Co., 53 FERC ¶ 61,473 (1990), order on reh'g, 55 FERC ¶ 61,084 (1991).

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64.  Seaway Crude Pipeline Company LLC, Opinion No. 546, 154 FERC ¶ 61,070, at P 47 (2016). “(T)here is extensive precedent that supports the Commission's policy that negotiated rates need not be cost-based, and that a pipeline's entire portfolio of rates can produce revenues that exceed its overall cost-of-service.”

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65.  For example, a negotiated rate could apply to the newer part of the pipeline system for which the rate base has not depreciated. In contrast, the cost-based rates may apply to older, legacy parts of the system in which the rate base has depreciated.

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66.  As an example, consider a pipeline that ships 100,000 barrels system-wide, where 50,000 barrels are shipped under an indexed rate of $1.00 ($50,000), 25,000 barrels are shipped under a negotiated discount rate of $0.90 (for revenues of $22,500), and 25,000 are shipped at a market-based rate of $2.00 ($50,000). Also assume a total cost-of-service of $100,000. Under the existing requirements of page 700, the pipeline would list total revenues of $122,500 (50,000 + 22,500 + 50,000), producing a deviation between cost and revenue of $22,500 or 22.5 percent. If this pipeline instead reported segmented revenue, it would report $50,000 in cost-based revenue and $72,500 in non-cost-based rate revenue. The pipeline would also report throughput of 50,000 cost-based barrels, and 50,000 non-cost-based barrels. Comparing cost-based revenue to cost-based throughput, there would be no deviation between cost-based costs ($50,000) and cost-based revenues ($50,000).

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67.  These additions comport to Dr. Arthur's statements in his testimony pointing out that “two additional significant areas where page 700 work papers provide relevant information not reported elsewhere in the Form 6 are the allocation factors used to derive the cost-of-service and the treatment of other non-trunkline revenue, both of which can have significant influence on a resulting cost-of-service and revenues.” See Joint Shippers Initial Comments, Arthur Affidavit, Docket No. RM15-19-000, at PP 6-7.

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[FR Doc. 2016-26227 Filed 11-1-16; 8:45 am]