Abstract
We demonstrate that the Federal Energy Regulatory Commission’s (FERC) regulatory procedures for natural gas pipelines, specifically its rate-refund policy, induces regulatory arbitrage that leads to economic distortions. Specifically, we demonstrate that the rate refund policy causes pipelines effectively to “extort” ratepayers through the addition of economically inefficient capital investment, akin to “gold-plating” investments. We estimate the potential magnitude of this arbitrage impact on ratepayers to be between $400 and $700 million annually. Counterintuitively, however, we demonstrate that the presence of this arbitrage opportunity leads to underinvestment in pipeline capacity, thus negating one of the principal purposes of rate regulation. We further demonstrate that FERC could easily eliminate this regulatory arbitrage by setting the refund interest rate to the pipeline’s as-filed weighted average cost of capital.
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Notes
FERC is the successor agency to the Federal Power Commission (FPC), which was renamed in 1977. Shortly after Congress passed the Natural Gas Act in 1938, the FPC prescribed a uniform system of accounts for interstate natural gas companies. See Phillips (1993) at p. 220. The FPC conducted its regulatory oversight of natural gas companies pursuant to the teachings of the Bluefield decision (1923), later supplemented by the Hope decision (1944). Bluefield Water Works et al. v. Pub. Serv. Comm. Of W.V., 262 U.S. 679 (1923); Federal Power Comm’n v. Hope Natural Gas Co., 320 US 591 (1944).
Averch and Johnson (1962), p. 1053.
“The Supreme Court’s concept of a reasonable return is really a notion of a zone of reasonableness. Confiscation of the property of a private company is the lower limit of the zone; exploitation of buyers, which is revealed by pricing practices and monopoly profits, is the upper limit. If the return is reasonable, it must fall within these limits.” Phillips (1993) p. 181, quoting Troxel (1947) p. 224.
The traditional view of A–J is reported by Crew and Kleindorfer (1986) at p. 121; “The Averch–Johnson effect has received more attention in the recent literature on the economic theory of regulation than any other topic.” More recently, Laffont and Martimort (2002) at p. 18 express the view that the A–J result has been “overemphasized.”
See 18 CFR §154.303.
Pipelines are required to maintain sufficient capability to perform they services for which their shippers have made “reservations.” However, as a practical matter, most shippers view the reserved capacity as a derivative instrument; to wit, a call on geographic basis differentials.
FERC policy provides that certain costs, specifically non-labor operations and maintenance (O&M) expenses in Accounts 863 (“Compressor Sta. Labor and Expenses”) and 864 (“Maintenance. of Compressor Station Equipment”), are deemed to vary with throughput. However, there are no litigated decisions establishing this “policy” nor, so far as we are aware, are they any studies establishing that the non-labor O&M costs so identified are not, in fact, “fixed” vis a vis throughput.
Although, in theory, a pipeline can file for a rate decrease, this is almost never done. Under § 5 of the Natural Gas Act (NGA), if FERC believes a pipeline to be earning excessive returns, the agency can force the pipeline to file what is essentially a rate case to justify its earnings and rates.
While there is no specific requirement to do so, the typical pipeline rate filing assembles Base and Test Periods in such a way that the Test Year ends at the same time as the longest suspension he FERC may impose under the NGA. See §4(d) and (e) of the NGA.
An “extremely complex” case which proceeds to trial is arranged so that an initial decision (ID) by the presiding judge will be issued about 63 weeks after the initial rate case filing. This is followed within 30 days by briefs on exceptions to the ID. The Commission is then left to deliberate on the exceptions before issuing an order on the ID, typically referred to as an “Opinion” and numbered. There is no specified or required schedule for the issuance of the Opinion. Such a decision typically takes a year or more. Following this, the parties are entitled to an opportunity to ask for rehearing, which rehearing proceeds on no specific time line, subject only to the Commission issuance of a tolling order. It is easy to see that the litigation path to a final determination in a rate case can (and has in many instances) be counted in years.
See NGA §4(e).
“When a pipeline files a motion to place the rates into effect, the filing must be revised to exclude the costs associated with any facilities that will not be in service as of the end of the test period, or for which certificate authorization is required but will not be granted as of the end of the test period. At the end of the test period, the pipeline must remove from its rates costs associated with any facility that is not in service or for which certificate authority is required but has not been granted.” 18 CFR §154.303(c)(2). Actual Test Period data is not revealed until 45 days after the end of the Test Period per 18 CFR §154.311, Updating of statements.
18 CFR §154.501(d)(1).
In reality, the rate base consists of net plant in service, or “undepreciated capital”, plus or minus various adjustments for prepayments, deferred taxes, miscellaneous regulatory assets and liabilities, and so on.
In the absence of compounding \(a(n)\approx n/2\).
Pursuant to NGA Sect. 4(e), the Commission “may, by order, require the natural gas company to furnish a bond” to secure the payment of refunds. However, it is not the Commission’s traditional practice to require a natural gas pipeline to guarantee refunds by posting a bond or other economic assurance. For example, in Distrigas of Massachusetts Corporation, despite the fact that Distrigas of Massachusetts’ customers had alleged that it was in financial difficulty and its affiliate, Distrigas Corporation, had filed for voluntary bankruptcy under Chapter 11 of the United States Bankruptcy Code, the Commission declined to require the furnishing of a bond; the Commission stated that it has not ordinarily required the furnishing of a bond, absent “extraordinary circumstances”. See Distrigas of Massachusetts Corporation, 33 FERC ¶61,406 at 61,776 (1985).
One can also think of (1) as the net benefit to the pipeline of putting the average balance of the refund obligation to work in the capital market at the rate \(\varpi _a \).
Given the analysis here, we must find this statement somewhat ironic.
See, for example, Laffont and Martimort (2002, pp. 240–244).
Practitioners will perhaps see in Eq. (5) why the agreed upon settlement COS in their case exceeded any reasonable estimate of the “true” COS plus out-of-pocket litigating expenses.
This is often a source of frustration for practitioners, who, after seeing the pipeline file an unreasonably excessive Test Period cost of service, plead for the FERC to reject it, and get denied. It is the Commission’s policy to let almost anything by way of costs be set for hearing. See, however, fn. 35 infra.
The spreadsheet we developed for this exercise is available from the authors on request.
FERC Form 2 presents a compilation of the calendar year financial and operating data of “major” interstate pipelines subject to the Commission’s jurisdiction. Among other things, the form contains a Comparative Balance Sheet, Statement of Income, Statement of Retained Earnings, Statement of Cash Flows, and Notes to Financial Statements. Major natural gas pipelines subject to FERC jurisdiction are generally required to file FERC Form 2 pursuant to 18 CFR § 260.1. Major is defined as having combined gas transported or stored for a fee that exceeds 50 million dekatherms. Non-major pipelines, defined as having total gas sales or volume transactions exceeding 200,000 dekatherms, are required to file FERC Form 2-A, which is essentially an abbreviated Form 2, pursuant to 18 CFR § 260.2.
The year 2007 was the last year in which the FERC made publicly available spreadsheet databases consisting of data from all pipelines filing Form 2 or Form 2-A. The format of these databases makes the exercise we propose here much more tractable than extracting data from each of the actual, individually filed Form 2s. The specific data set used here consists of Form 2 and 2-A data from 113 reporting pipelines. Our typical pipeline is based on the average value of reported data such as gross plant in service, deferred income taxes, regulatory assets and liabilities, O&M expenses and so on.
The capital cost parameters assumed for our rate case filing are taken from the recent general Sect. 4 rate filing of a major pipeline. We consider these parameters to reflect an exaggeration in capital costs inasmuch as the proposed cost rates are high relative to the results of a recent fully litigated case. See El Paso Natural Gas Company, Opinion No. 528, 145 FERC ¶61,040 (2013), on reh’g, Opinion No. 528-A, 154 FERC ¶61,120 (2016) (El Paso). Note that, in this case, Motion Rates went into effect on April 1, 2011. Thus, almost 5 years passed between the effective date of the motion rate filing and the issuance of a “final” Commission order in this general rate proceeding.
The $161.6 million covers all expenses and produces an after-tax ROE of 14.86% on the proposed equity rate base.
See El Paso.
The 50/50 capital structure is typically what the FERC will assume and adopt for a pipeline in the face of an anomalous capital structure proposal by that pipeline. See, for example, Natural Gas Pipeline Company of America LLC, 158 FERC ¶61,044 (2017); Wyoming Interstate Company, L.L.C., 158 FERC ¶61,040 (2017). See also Alabama-Tennessee Natural Gas Company, Opinion No. 268, 38 FERC ¶61,251, reh’g granted in part and denied in part, Opinion No. 268-A, 40 FERC ¶61,244 (1987) (The Commission revived the use of hypothetical capital structures. The Commission explained the necessity of imputing hypothetical capital structures to mitigate the effects on ratepayers of abnormally high equity ratios. Where use of an actual capitalization of either the parent or subsidiary would lead it to prescribe “anomalous” rates of return, the Commission found that it made more sense to impute a reasonable capital structure, i.e., 55% Equity, 45% debt, and establish a normal rate of return. At pp. 61, 849–850.)
See El Paso and fn. 27.
The FERC currently requires the payment of 3.5% interest on refunds. Current and historic refund rates are available at the FERC website: https://www.ferc.gov/enforcement/acct-matts/interest-rates.asp.
The $2.3 to $3.8 million corresponds to the \((\varpi _a -i)a(n)[(\hat{{\varpi }}-\varpi _a )k]\) component shown in Eq. (5).
This is the average pipeline’s contribution multiplied by 113 (that is, the average balance of the “loan” times the true WACC times 113).
The assumption that \(q_T =q(k)\)ignores the incentives that the regulated firm may have to understate Test Period volumes and accordingly increase the Motion Rates and the resulting extortion rents. Here we are assuming that \(q_T \) and \(\hat{{\varpi }}\) are not choice variables when in reality they clearly are part of the decision process for the regulated firm assembling the rate case. By so doing, we are essentially invoking the Commission’s authority to reject a rate filing; the pipeline can understate Test Period volume and exaggerate its WACC, but its latitude in doing so is constrained by the Commission’s oversight and the risk of rejection of the pipeline’s Case in Chief. Under the NGA, the Commission may reject rate filings based on a summary disposition of an issue if the disposition is based on a rule, regulation, clear policy, or any issue where the facts are not in dispute. See United Gas Pipe Line Co. v. FPC, 551 F.2d 460 (D.C. Cir. 1977); United Gas Pipe Line Co., 19 FERC ¶61,060 (1982); Cities Service Gas Company, 5 FERC ¶61,137 (1978). See, for example, El Paso Natural Gas Company , 44 FERC ¶61,047 at 61,133 (1988); “As the filing was in clear conflict with ...existing Commission policies, there was no ‘need to ventilate the underlying facts to aid in policy determination,’ and there were no facts in dispute regarding the application of that policy which would require a hearing, rejection was appropriate. Rejection of a tariff filing may be used by an agency where the filing is so unacceptable ‘as a matter of substantive law, that administrative efficiency and justice are furthered by obviating any docket at the threshold rather than opening a futile docket.”’ Citing Municipal Light Boards v. FPC, 450 F.2d 1341 (D.C. Cir. 1971), cert. denied, 405 U.S. 455 (1972).
If \(q_T =q(k)\)then \(M(k)=C(k)+e(k)\) and \({M}'(k)-{C}'(k)={e}'(k)>0\). The firm’s incentive would be to understate volumes (i.e., \(q_T <q(k)\) ) and \({M}'(k)-{C}'(k)>0\) always.
The regulatory mechanism is undermined to the extent that the FERC’s interest rate on refunds rule reduces output and capacity.
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Briden, G., Lesser, J. Regulatory arbitrage and the FERC rate settlement process. J Regul Econ 51, 184–196 (2017). https://doi.org/10.1007/s11149-017-9322-1
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DOI: https://doi.org/10.1007/s11149-017-9322-1