Zone of Reasonableness

During the past three years, the Federal Energy Regulatory Commission (the FERC) has initiated five investigations into the justness and reasonableness of interstate gas pipeline rates.¹ Under the Natural Gas Act of 1938 (the NGA), the FERC has a statutory obligation to assure that such pipelines rates are just and reasonable. Case precedent makes clear that no single just and reasonable rate exists for a given pipeline at a given time; instead, for rates to meet the just and reasonable standard, they must remain within a zone of reasonableness. In judicial review of its decisions, the courts have held the FERC to an end result within that zone.² The FERC initiated the examination of these five pipelines’ rates precisely because their Form 2 financial data appeared to indicate excessive profitability falling outside that zone.

For interstate gas pipelines, the passage of time can lead to rates that exceed the cost of service because traditional ratemaking is front-loaded by the nature of straight-line depreciation of pipeline investments. Such is particularly true for gas pipelines since the FERC invoked the standard of “incremental” pricing for new capacity additions, which effectively segregates the cost of service for new projects from the pipeline property that supports existing shipper capacity entitlements.³ Without the need to invest in new pipeline equipment to support existing capacity contracts, the passage of time will drive down the rate base supporting existing contracts through depreciation. This in turn lowers the financing charges associated with carrying the rate base, and therefore lowers the cost of service.⁴ Traditional ratemaking, however, requires that rates stay constant in dollar terms until the next rate case. In the period before the restructuring of pipeline regulation was completed in about 2000, the FERC required pipelines to file periodic NGA Section 4 rate cases to assure that rates didn’t stray too far from the cost of service. With the implementation of open access, incremental pricing and competitive gas transport culminating in Order Nos. 636⁵ and 637,⁶ however, FERC eliminated the ongoing requirement for pipelines to file regular Section 4 rate cases.

The elimination of periodic rate cases places a greater burden on shippers to monitor the rates they pay (under their capacity contracts) and on the FERC itself to screen pipeline returns and to identify excessive returns. While the FERC may have hoped that its competition-friendly policies, which include allowing pipelines to adopt alternative ratemaking practices and to negotiate rates with their customers,⁷ would allow shippers and the pipeline to find a set of mutually-agreeable rates and limit the need for litigated proceedings, FERC’s oversight responsibilities are as important today as they ever have been. Although FERC’s 1996 policy statement did envision that some pipelines would be able to meet the criteria for market-based rates, no pipeline to date has been able to meet those criteria. Indeed, the one pipeline that made an attempt to apply for the loosened regulation of rates was shot down by the FERC with such finality—on the subject of the inherent market power of pipelines over captive customers—that no other pipeline has tried again.⁸ The FERC thus continues to be the judge of just and reasonable rates when shippers and pipelines are unable to find mutually-agreeable solutions. While many pipelines now have an incentive to delay scrutiny of their rates and cost of service for as long as possible, the declining rate base phenomenon makes it important for shippers and the FERC to monitor pipeline profits judiciously to assure that rates and costs don’t unduly diverge.

How does the FERC decide whether to initiate an investigation to determine whether a given pipeline’s rates fall outside the zone of reasonableness? The screen that the FERC uses is the earned return on common equity (ROE), as indicated by the data submitted by pipelines in Forms 2 and 2-A. Because many variables are at play in a detailed rate case review, however, the earned returns implied by Forms 2 and 2-A can only serve as initial indicators of profitability and a signal as to whether a more detailed review of cost and revenue is necessary.

Earned Returns

To assess the ROE for 2010, the rates and cost of service for 68 interstate gas pipelines with gas plant exceeding $200 million were analyzed in a four-step process: 1) Estimate the pipeline’s revenue requirement using traditional cost-of-service ratemaking techniques, excluding ROE and income taxes. The revenue requirement includes standard expense items such as depreciation, operation and maintenance costs, interest, other taxes and administrative and general costs. The pipelines report these directly on Form 2.⁹ They also report on Form 2 the asset account balances needed to determine the pipeline’s rate base. 2) Calculate pre-tax net income by subtracting the estimated revenue requirement from actual revenues. 3) Calculate after-tax net income by subtracting income taxes from pre-tax net income, using the pipeline’s composite tax rate. 4) Calculate ROE by dividing after-tax net income by the amount of common equity in rate base.

Because the ROE is highly sensitive to the level of equity permitted in the capital structure, and further because many pipelines that are as subsidiaries of larger holding companies have unusual capital structures by regulatory standards, the ROEs were calculated using both the reported capital structure and under the assumption that the FERC would require that the pipeline set rates based on a hypothetical capital structure containing 50 percent equity¹⁰ (See Figures 1 and 2).

The largest allowed return on equity given by FERC to any pipeline in the last decade is 14 percent.¹¹ As a result, this screening of pipelines’ ROE suggests that rates of return for many pipelines not yet investigated by FERC may be well outside the zone of reasonableness. That FERC has initiated investigations of only a handful of pipelines is surprising in light of these data. The returns on equity that triggered the five rate investigations all exceeded 20 percent—averaging 26 percent, almost double the FERC’s largest recent granted ROE.

As Figure 2 indicates, a limited number of pipelines have achieved very low levels of return—in some cases negative. This phenomenon is partly the result of negotiated rates that levelize pricing for shippers, and back-load the return to equity investors. FERC’s 1996 policy statement on pipeline pricing encouraged the use of negotiated rates, and levelized ratemaking has been accepted by FERC for a number of pipelines.

It’s only fair to judge any such presentation of ROEs against the underlying risk to which such equity is applied, which is how the capital markets evaluate the adequacy of returns. Equity investments are by nature contingent claims; equity investors receive returns from their investments only after debt holders have received their contractual interest payments. Capital structures employing high levels of debt subject equity investors to more financial risk than capital structures with less debt. All other things being equal, high levels of financial risk increase the required rate of return for equity investors. The FERC recognizes this fact when exercising its ratemaking authority. For example, the FERC has repeatedly granted a 14 percent rate of return on equity for “greenfield” pipelines whose equity investors not only face development risk, but also significant financial risk—e.g., with debt comprising 70 percent of committed capital—while granting lower rates of return for pipelines with less debt leverage. To evaluate whether a given return on equity is excessive, one must consider not only the business risks that equity investors confront, but also the financial risk. Capital structure is therefore a pivotal variable in assessing whether the current profits accruing to equity investors lie within a zone of reasonableness.

The FERC’s policy on capital structure is to try to rely on actual verifiable data: that is, on a pipeline’s actual capital structure when the pipeline raises its capital directly or otherwise on the parent company’s capital structure. The FERC will only turn to a hypothetical capital structure if it deems that the level of equity is unreasonably high, particularly with reference to observed capital structures in a group of stand-alone pipelines that it concludes are comparable to the pipeline in question.¹² Thus on numerous occasions the commission rejected high equity ratios proposed by a pipeline and assumed a reasonable use of debt capital.¹³

Why Returns Increase

Although declining rate base goes far in explaining many pipelines’ steadily increased returns, natural gas market dynamics have also helped their financial results to remain strong. In 2010, domestic natural gas production and consumption reached record levels. These records reflect a long-term trend of strong growth in natural gas demand that began in the mid-1980s. Since then, natural gas has become the fuel of choice for much of the nation’s new electricity generation. Further, natural gas demand for residential, commercial and industrial uses has also grown. In the United States, gas-on-gas competition—that is, competition among different sources of gas including traditional gas sources, shale gas and LNG—has kept prices down, while prices for other hydrocarbons have risen considerably. The favorable market dynamics in natural gas have allowed most pipelines to remain fully-subscribed (with capacity contracts) and to maintain high utilization factors.¹⁴ Of course, regional differences in the supply-demand balance, additions of new pipeline capacity, and storage additions naturally lead some pipelines to fare better than others.

Pipeline investors believe the strong growth in natural gas supply and demand will continue. Consequently, they have begun a wave of new pipeline construction across the country. A recent industry report by the Department of Energy’s Energy Information Administration explains the growth trend:

Favorable market and regulatory conditions explain why many pipeline investors are doing so well in spite of the economic downturn and lower overall interest rate environment. In such an investment environment, reliable gas pipeline rate base is a highly attractive asset—particularly if ROEs automatically trend upward over time without attention from the FERC or the groups holding the bulk of capacity contracts (gas utilities or power plants).

FERC Remedies

Under NGA Section 5, the FERC can initiate an investigation of pipeline rates on its own motion or “upon complaint of any State, municipality, State commission, or gas distributing company.”¹⁶ However, there are significant limitations under Section 5 of the Natural Gas Act that significantly limit its effectiveness in remedying unjust and unreasonable pipeline rates.

A Section 5 proceeding is very different than the typical rate increase case that a pipeline files under Section 4. The most critical difference is that any rate reduction under Section 5 will take place prospectively only, either upon the date of a FERC decision of the appropriate rate or a FERC order approving a negotiated settlement rate. A Section 4 proceeding, by contrast, automatically adopts the newly-filed pipeline rates no later than five months after filing, with a refund (one way or the other) once the FERC makes its final determination.

Because of the limitations of Section 5, pipelines have inherent financial incentives to delay resolutions of Section 5 proceedings—and corresponding disincentives to settle cases. While there may be costs the pipeline incurs in litigation, they are typically much more than offset by reduced rates made effective sooner than in a fully-litigated case. A related effect is that any rates agreed on in settlement of a Section 5 investigation generally include a premium to the pipeline as an inducement to allow a reduction in rates to take effect sooner than would otherwise occur.

Other than the existing asymmetry with respect to ratemaking relief, there’s one other important difference between Section 5 and Section 4 proceedings. By regulation and precedent, rates in a Section 4 proceeding are determined based on costs incurred and revenues received during a defined 12-month test period. In contrast, there are no regulations, nor any reliable precedents, defining the specific cost period to be used to determine the appropriate rates in a Section 5 proceeding. The FERC at the outset of a Section 5 proceeding typically requires a pipeline to file a cost and revenue study using the most recent 12-month period for which data is available. However, the FERC also allows the pipeline to propose adjustments to the historical data.¹⁷ The absence of clear guidance disadvantages a pipeline customer, as it invites complication in the development of an evidentiary record and gives the pipeline the opportunity to provide evidence on costs and revenues from different time periods to justify existing rates. Overall, there are many FERC-regulated pipelines that are earning rates of return well in excess of that which would be allowed in a litigated proceeding, and yet they haven’t been subject to any investigation under Section 5. The inherent obstacles associated with pursuing rate reductions under NGA Section 5 help to explain why.

There are only two instances within the last 10 years in which a complaint was filed by customers or a state commission that prompted the FERC to initiate a Section 5 investigation into the existing rates of a pipeline—one against National Fuel Gas Supply¹⁸ and the other against Southwest Gas Storage.¹⁹ In both instances, the FERC granted the request of the complainant to initiate an investigation by directing the pipeline to file a cost and revenue study for the most recent 12-month period. However, in both proceedings, customers were significantly disadvantaged by the limitations of Section 5.

In National Fuel, the FERC rejected a request by customers to reduce immediately the fuel retention factor of the pipeline, based on an argument that the existing fuel factor had over-recovered fuel by substantial amounts based on pipeline-supplied data for a recent 12-month period.²⁰ Customers eventually achieved a settlement that reduced in substantial part the over-recovery of fuel, but left the non-fuel (or “base rate”) elements of the pipeline’s rates unchanged.

In Southwest Storage, the commission rejected a motion for waiver of the administrative law judge’s initial decision and motions for an immediate, interim reduction in rates.²¹ Customers negotiated a settlement that provided for no change in any of the pipeline’s rates.

Ultimately, the FERC seems to have the power to order interim relief in particular cases. But such Section 5 relief sought by gas distributors, state commissions or the FERC itself requires evidence and argument on the part of those parties asking for relief that must compete with counter-evidence and argument brought by pipelines. In contrast, the timing of Section 4 relief for pipeline companies is automatic. Given the perceived shortcomings of Section 5, Congress faces pressure to amend it and allow for refunds on a retrospective basis.²²

Zone of Reasonableness

When prima facie indicators suggest that rates are outside the zone of reasonableness for interstate pipelines, the customers of those pipelines should press the FERC to act to protect the public interest and engage the pipelines in detailed rate reviews. The level of earned returns for the pipeline sector today calls for more rate scrutiny and additional activity before the FERC.

The lack of periodic Section 4 rate cases, as in the old days before regulatory restructuring for this industry, means that shippers and the FERC must more be diligent in monitoring pipelines’ financial results. Legislative changes would improve the ability of FERC to ensure that shippers of natural gas on interstate pipelines pay just and reasonable rates. Absent legislative changes to broaden FERC authority under NGA Section 5, however, it will take significant collective shipper efforts, and a determined FERC, to assure that gas transportation rates remain just and reasonable.

Endnotes:

1. See: Ozark Gas Transmission LLC, 133 FERC ¶ 61,158 (2010); Kinder Morgan Interstate Gas Transmission LLC, 133 FERC ¶ 61,157 (2010), reh’g granted in part and denied in part, 134 FERC ¶ 61,061 (2011); Natural Gas Pipeline Co., 129 FERC ¶ 61,158 (2009), reh’g denied, 130 FERC ¶61,133 (2010); Northern Natural Gas Co., 129 FERC ¶ 61,159 (2009), reh’g denied, 130 FERC ¶ 61,134 (2010); Great Lakes Gas Transmission Limited Partnership, 129 FERC ¶ 61,160 (2009), reh’g denied, 130 FERC ¶ 61,132 (2010).

2. See: Permian Basin, 390 U.S. at 797, 88 S.Ct. 1344; Pub. Serv. Comm’n of Ky., 397 F.3d at 1009.

3. See: “Policy Statement on Determination of Need,” 1902-AB86, FERC Docket No. PL-3-000.

4. Many variables determine a pipeline’s cost of service. The passage of time doesn’t always lead to a decline in the cost of service for certain contracted capacity, particularly for pipelines requiring major capital improvements to existing infrastructure. In addition, some pipelines may seek to levelize their rates over a given time period, which would affect year-by-year ROE calculations.

5. 59 FERC ¶ 61,030, 18 CFR Part 284 (Order No. 636), April 8, 1992.

6. 90 FERC ¶ 61,109, CFR Parts 154, 161, 250, and 254 (Order No. 637), Feb. 9, 2000.

7. See: “Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines,” 74 FERC ¶ 61076, 1996.

8. “Koch has not met the requirements of the Policy Statement and has not shown that it lacks market power.” Docket No. RM-95-6-000, Order Reversing Initial Decision, p. 23.

9. The data for this study were obtained through SNL Financial. Form 2 data for Accounts 117.1, 117.2, 283, “Fuel Recoveries and Commercial and Industrial Sales,” weren’t available through SNL and are excluded from the analysis.

10. This assumption is consistent with the commission’s representative ruling in Ingleside Energy Center, rejecting the use of a 70 percent equity ratio proposed by the developer and required that a 50/50 debt-to-equity capital structure be used for ratemaking purposes. See 112 FERC ¶ 61101, 2005.

11. This 14 percent return on equity was allowed for greenfield pipelines with substantial financial leverage such as Colorado Interstate Gas Co (Docket No. CP03-7), AES Ocean Express (Docket No. CP02-90), Sonora Pipeline LLC (Docket No. CP07-74), Trans-Union Interstate Pipeline (Docket No. CP01-37) and Tractebel Calypso Pipeline (Docket No. CP01-409).

12. The Commission has found that “a large equity ratio is more costly to ratepayers, since equity financing is typically more costly than debt financing, and also because the interest on indebtedness is tax deductible.” See Ingleside Energy Center, 112 FERC ¶ 61101, 2005.

13. See, e.g., Schneidewind v. ANR Pipeline Co., 485 U.S. 293, 302 (1988) (“Thus, FERC exercises its ratemaking authority to limit the burden on ratepayers of abnormally high equity ratios.”); Transcontinental Gas Pipe Line Corp., 71 FERC ¶61,305 (1995) (“[t]he determination of an appropriate capital structure involves a balancing of the investor and consumer interests. Equity generally costs more than debt. Hence, ratepayers would be subjected to an excessive burden if their rates had to be set at a level high enough to compensate the pipeline for excessive equity in its capital structure. This burden on ratepayers can be limited by ‘levering a capital structure with lower-cost debt.’”)

14. The imposition of ratemaking based on contract levels, rather than flowing volumes, makes pipeline revenues highly predictable for pipelines that are fully-subscribed with such contracts, which is the case for most interstate pipeline capacity.

15. Expansion of the U.S. Natural Gas Pipeline Network: Additions in 2008 and Projects through 2011, Energy Information Administration, Office of Oil and Gas, September 2009.

16. Natural Gas Act of 1938, 52 Stat., pp. 823.

17. Kinder Morgan Interstate Gas Transmission LLC, 133 FERC ¶61,157 (2010), reh’g granted in part and denied in part, 134 FERC ¶61,061 (2011).

18. Public Service Comm’n of N.Y. v. National Fuel Gas Supply, 115 FERC ¶61,299 (2006).

19. Panhandle Complainants, v. Southwest Gas Storage Company, 117 FERC ¶61,318 (2006).

20. Public Service Comm’n of N.Y. v. National Fuel Gas Supply, supra.

21. Panhandle Complainants, v. Southwest Gas Storage Co., 120 FERC ¶61,207 (2007).

22. The Senate Energy & Natural Resources Committee examined NGA reform and voted in June 2009 to reject an amendment that would have modified Natural Gas Act Section 5 to provide the FERC with the authority to grant refunds to consumers that are paying unjust and unreasonable pipeline rates. In 2010, however, FERC Chairman Jon Wellinghoff continued to communicate his support for legislative changes to the evident asymmetry between Section 4 and Section 5 remedies under the NGA. See: 131 FERC ¶61,178 (dissenting opinion to an order issued May 27, 2010, in Docket No. RP10-148-000, Issued June 8, 2010).