FERC and the Tax Cuts and Jobs Act of 2017 – Natural Gas Pipelines

By Joel Zipp, Barbara de Marigny, Erik Swenson and Lisa Tonery

The Federal Energy Regulatory Commission (FERC) Staff has initiated inquiries involving numerous interstate natural gas pipelines, seeking information on the impact of the Tax Cuts and Jobs Act of 2017 (Tax Act)^[1] on those pipelines’ cost-of-service which, in turn, drives the maximum recourse rate allowed to be charged by such pipelines. Among other things, the Tax Act reduces corporate income tax rates from 35 percent to 21 percent and affords certain investments bonus depreciation, which may reduce the pipelines’ cost of service. FERC has requested that certain pipelines submit (within just a few business days of the request) an adjusted cost-of-service study and a recalculated initial incremental rate.

Additionally, consumer groups and others have filed requests for immediate action on the rates charged by natural gas pipelines to reflect the corporate tax reduction,^[2] and public statements by the FERC’s Chairman and other Commissioners reported in the trade press leave little room to doubt that adjustments to rates will be required.^[3] Indeed, in some cases, FERC has already imposed such requirements. For example, in its January 19, 2018 Order Issuing Certificates in PennEast Pipeline Company, LLC, FERC Docket No. CP15-558-000,^[4] FERC ordered PennEast to reduce its rates to reflect the reduction in corporate income tax rates under the Tax Act.

Whether the Tax Act will require a rate adjustment, and when the benefit will be reflected in a shipper’s rate, depends on a variety of circumstances, including the status of the pipeline and the language in any transportation agreements between the pipeline and shipper. Pipelines and shippers will need to consider whether:

1) the pipeline has received a certificate from the FERC;

2) the pipeline is an incumbent that has been in operation;

3) the pipeline is a new project that has commenced service, but has not had its rates reviewed and approved by FERC under Section 4 of the Natural Gas Act;

4) the pipeline’s rates are fixed (e.g. via a rate moratorium) under a settlement agreement with its shippers for a period of time;

5) the pipeline is organized as a tax pass-through entity, such as a master limited partnership (MLP) or limited liability company (LLC);

6) the transportation agreement between the pipeline and shipper has been filed with, and accepted by, FERC as a so-called “negotiated rate agreement”;

7) the particular service is provided under FERC-approved market-based rate authority (usually limited to gas storage, hub or wheeling services); or

8) the current rate is an NGPA section 311 rate.

In brief, if a pipeline company’s application is pending before the FERC and is backed by executed precedent agreements or other agreements with shippers that provide the tariff recourse rate applies to the transportation service, the parties should expect that the FERC will order a reduction in those tariff rates. The same general rule applies to existing transportation services on existing pipelines. However, this may be complicated because many existing pipelines are operating under FERC-approved settlement agreements between the pipeline and its shippers. Those settlement agreements often do not permit any changes in rates for a period of time (i.e. a rate moratorium). Additionally, many of these are black-box settlements that do not contain a derivation of the rate that would lend itself to a straightforward recalculation of the rate. The burden of proof on a change in such rates may very well lie with the aggrieved party (if Mobile-Sierra Doctrine considerations even allow a change to be initiated by the aggrieved party) or FERC (if the existing contract terms threaten the public interest). Additionally, in the event a recalculation of rates is ordered by FERC, the pipeline would arguably be allowed to file a general Section 4 rate case to reflect all changes in its cost of service, which would include increases in costs that might offset any reductions anticipated from the Tax Act, such as new limitations on tax deductions in the Tax Act.

A subcategory of pipelines falls between the two mentioned above. These are newly certificated pipelines with rates approved in the certificate order issued by the FERC as “initial rates.” At such a stage, no rates have been approved by FERC in a general rate proceeding under Section 4 of the Natural Gas Act. While the FERC cannot force a pipeline to file a general Section 4 rate case, a typical condition in a newly certificated pipeline is the requirement that the pipeline file a cost and revenue study after three years of operation to justify its existing rates. FERC could act in these situations prior to the three-year period under Section 5 of the Natural Gas Act. However, any relief would be prospective.

If the pipeline is organized as a pass-through entity (e.g. a LLC or MLP), the situation is complicated since these entities are already subject to the outcome of an ongoing FERC inquiry regarding the recovery of income taxes in rates, due to the Court of Appeals July 2016 decision in United Airlines.^[5] As noted below, there is pending at FERC a request to immediately flow through the benefits of the Tax Act.

A special category of agreements involves negotiated rates that have been filed with and accepted by FERC. The parties have often protected these agreements under Mobile-Sierra provisions, which require a higher burden in order to change the agreement. And, if these changes are made under Section 5 of the Natural Gas Act, relief will be prospective. Moreover, requiring a change in the rates to reflect the Tax Act might very well trigger other provisions under the agreement.

Those parties operating under services provided at market-based rates should not expect to see FERC involving itself in those rate determinations. However, some shippers might very well see competing services offered under cost-of-service derived rates reduced to levels below the market-based rate. This would create downward pressure on existing market-based rates.

Similarly, for Section 311 rates, which must be “fair and equitable,” the FERC arguably has authority to change such rates approximately equivalent to its authority under the Natural Gas Act. While there does not appear to be instances where the FERC has acted entirely on its own to adjust 311 rates, the NGPA provides that “fair and equitable” rates must be comparable to “just and reasonable” rates under the Natural Gas Act.

Some of these issues are already on display in recent filings at the FERC made in response to FERC Staff inquiries through data requests:

DTE Midstream Appalachia, LLC, FERC Docket No. CP17-409-000 – The FERC Staff issued a data request to DTE Midstream involving its proposed Birdsboro Pipeline Project, asking the pipeline to explain how “a reduction in the federal income tax rate to 21 percent and allowing certain investments to receive bonus depreciation treatment…” affect the proposed rate and to provide an adjusted cost of service and recalculated rate.^[6] The company’s January 18, 2018 response^[7] showed a reduction of $957,947.00 in its cost of service, which resulted in a recalculated initial rate of $0.2623/dth reflecting a decrease of $0.0332/dth from the proposed initial rate. The company stated the bonus depreciation treatment does not apply to its project since it is not using that method of cost recovery.

Gulf South Pipeline Company, LP, FERC Docket CP17-476-000 – In response to the same data request on Gulf South’s proposed Westlake Project, Gulf South explained that the only shipper on the lateral had agreed to a negotiated rate that does not adjust due to any changes in the maximum recourse rate.^[8] Gulf South also noted that its system-wide recourse rates are subject to a rate case moratorium through May 1, 2023, but that, nonetheless, those adjustments will take place before the expiration of the negotiated rate agreement. The implication is that the shipper is not entitled to receive a lower rate reflective of Gulf South’s reduced costs stemming from the newly lowered corporate income tax rate.

Paiute Pipeline Company, FERC Docket No. CP17-471-000 – In this proposed 2018 Expansion Project, Paiute explained that under FERC decisions it “is required to use its most recently approved rate of return and depreciation rates.”^[9] For Paiute and its shippers, that is a rate developed in a black-box settlement and approved by FERC in 2015. According to Paiute, “[d]ue to the ‘black box’ nature of the settlement agreement only specifying the pre-tax rate of return, Paiute is unable to recalculate an initial incremental rate to reflect a revised income tax expense using a federal income tax rate of 21 percent. A revised income tax expense cannot be calculated without specific debt and equity cost rates and a debt-to-equity ratio.”^[10] By contrast, adjusting for the changes in the bonus depreciation rate and tax rate causes a recalculation of the deferred income taxes, which results in a rate increase from $41.0537 to $45.4780 per dekatherm.

Southern Natural Gas Company, L.L.C., FERC Docket No. CP17-46-000 – In this proposed Fairburn Expansion Project, Southern explained that, since it will file a Section 4 rate case in February 2018 with an effective date of October 2018, the project will qualify for rolled-in rate treatment and the rates to be paid by shippers will be subject to adjustments that reflect the Tax Act of 2017.^[11] However, Southern Natural was careful not to promise whether its rates would increase or decrease overall.

Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs, FERC Docket No. PL17-1-000 – A motion for summary judgment was filed with the FERC on January 2, 2018,^[12] which, if granted, would require, on an industry-wide basis, that all pass-through entities (e.g. LLCs, MLPs) make two changes in their rates to reflect: 1) “a 20% tax cut on partners and other owners of pass-through entities”^[13] plus 2) the lower corporate and individual taxes paid by the owners of pass-through entities used in the FERC’s calculations of taxes paid by pass-through entities. The first of these two changes would result from the fact that, under the Tax Act, taxable income allocated to partners is eligible for a deduction of 20 percent of such income. If an individual has an otherwise applicable tax rate of 37 percent, then the result of deducting 20 percent of the income brings the blended rate on the income down to 29.6 percent.