Pipelines Assessing Impact From FERC Tax Orders, With a Lot Yet to be Decided

Much as a natural gas pipeline trade group asserted before FERC tackled the rate implications of the tax reform law, the effects of the rulings appear to be varied among different entities, based on their rates and contracts with shippers.

The rulings could have a major impact for some pipelines and be a non-event for others, with the result determined by the details of contracts and rates known only by the pipelines until they make their informational filings with FERC, sources have indicated.

Prior to FERC issuing the orders on March 15, the Interstate Natural Gas Association of America (INGAA) suggested that FERC avoid a one-size-fits-all approach and allow each pipeline to act on any rate adjustments based on their unique circumstances in individual proceedings. The timing of any rate relief is a point of contention with some pipeline shippers, asserting that the regulatory process will drag out and delay any rate reductions associated with lower corporate taxes in pipeline rate structures.[1]

At this point in the proceedings, it is hard to provide a broad assessment for the pipeline sector, although several companies have said they expect a limited financial impact, analysts said. In the fallout of the various orders issued addressing the Tax Cuts and Jobs Act of 2017, they expect natural gas pipelines to be affected sooner than crude oil or refined product pipelines. The exact impact, however, will depend on the details of pipeline contracts with shippers, which vary, and how the Commission will treat rates subject to “black box” settlements.

The lack of clarity on the treatment of rate settlements is one of the more striking issues associated with the orders, said Gary Kruse, director of pipeline markets at LawIQ. Both Kruse and Christine Tezak of ClearView Energy Partners LLC noted that in 1987, when FERC addressed tax reform legislation passed in 1986, it ruled that recourse rates that were the product of “black box” settlements would remain in place.

“They didn’t say that this time,” leaving it to be determined based on the informational filings to come from pipelines in response to the notice of proposed rulemaking (NOPR), Kruse said. Several pipeline parent companies issued statements that they expect limited impact because, among other things, they have settlement rates in place. But if those settlements do not have a rate moratorium in them limiting any change, they may not be immune to a rate revision, Kruse said in an interview.

“We fully expect FERC to honor any rate moratorium in place” within a settlement, but some moratoriums might have expired or have other provisions that allow future revisions, Kruse said. “This all gets back to the notion that the impact for each pipeline depends on the details” of its contracts with shippers, he said.

Tezak had a similar comment in a March 16 assessment of FERC’s orders, which included the NOPR (RM18-11), a revised policy statement (PL17-1) that FERC will no longer allow pipelines owned by master limited partnerships (MLPs) to recover an income tax allowance in cost of service rates, a notice of inquiry (RM18-12) and individual orders involving electric utilities and pipelines.

In the NOPR for intrastate and interstate natural gas pipelines, FERC directed pipelines to file a one-time information report, called a FERC Form 501-G, on the expected impact of the law and planned changes to the Commission’s tax allowance policies. Companies then would then have four options: make a limited Natural Gas Act (NGA) Section 4 filing to reduce rates; make a commitment to file a general NGA Section 4 rate case in the near future; file a statement explaining why a rate adjustment is not needed; take no action other than making the informational filing. If either of the latter two options are chosen, FERC will consider, based on the information provided in Form 501-G and comments by interested parties, whether to issue a show cause order under NGA Section 5 calling for a pipeline to adjust its rates or explain why it should not be required to do so.

Because FERC did not clearly state its expected treatment of settlement rates, pipelines with rate settlements in place may try and make the case that the settlement should not be altered when they make their informational filings, Tezak said. “The Commission has not indicated that it will preserve all settlements, but does acknowledge that it may be appropriate to leave certain rate moratoria undisturbed . . . This apparently will be addressed on a case-by-case basis,” she wrote.

FERC encouraged pipelines to meet with their customers and perhaps reach an agreement on a rate adjustment as the NOPR is implemented. ClearView expects some voluntary rate reductions through settlements to be in place before the end of 2018.

LawIQ believes all pipelines will have discussions with shippers about the tax change and rate impact, but unless they are on the cusp of being deemed overearning, they would have a limited incentive to reach a settlement with reduced rates, Kruse said. Those that would voluntarily reach an agreement are those with earnings on the high side under FERC’s methodology, he said.

Among the major pipelines, Transcontinental Gas Pipe Line Corp., owned by The Williams Companies Inc. and Williams Partners LP, is due to file an NGA Section 4 rate case later this year, and might reach a settlement on the issues as a final rule is being implemented, Kruse suggested.

In the revised policy statement eliminating the tax allowance in cost of service rates for MLPs, FERC was responding to a remand from the U.S. Court of Appeals for the District of Columbia Circuit in an oil pipeline case (United Airlines Inc. v. FERC, 827 F.3d 122 (D.C. Cir. 2016)) involving SFPP L.P.

The ruling will apply to oil and natural gas pipelines owned by MLPs, and similar to the NOPR could have different impacts on companies based on their ownership and rate structure. Kinder Morgan Inc., which owns the largest natural gas pipeline network in the U.S. and in 2014 changed from an MLP to a C-corporation, noted the corporate change in a March 15 statement that it would not be affected by the move.

Financial analysts have said that the decision will affect MLPs with a heavy reliance on regulated pipelines and rates for their income, which could be reduced substantially by not including the tax allowance as part of the cost of service. FERC chose not to alter the discounted cash flow (DCF) methodology used to set a return on equity, providing an option to make adjustments through that ratemaking process.

Following a stock drop for MLPs on March 15, the day FERC approved the orders, several companies issued statements that the rulings are expected to have a limited impact on their revenues. Several mentioned that their revenue is primarily based on negotiated rates or other types of contract that limit revenue from cost of service rates.

Willams, owner of Transco, Northwest Pipeline and a 50% interest in Gulfstream Natural Gas System, said negotiated rates make up about half of Transco’s revenue and all of Gulfstream’s revenue and would not be affected by the tax disallowance for cost of service rates. Given the limited impact on revenue, the company does not expect the decision to affect earnings guidance, expected dividends or growth rates, said Alan Armstrong, president and CEO of Williams.

However, the company appears to be considering a change away from a partnership. “As we’ve often discussed, we are well-positioned to execute on corporate structure changes, which would restore the income tax allowance to the pipeline’s cost of service rates,” Armstrong said.

Enbridge Energy Partners LP said it intends to seek rehearing of the FERC decision on MLPs, and that its revenues will be reduced due to certain cost of service rates on its pipelines, such as the Lakehead Facility Surcharge Mechanism.

If the policy statement is implemented as planned by FERC, the 2018 financial impact to Enbridge is expected to be a $100 million reduction in revenues and a $60 million reduction in distributable cash flow, net of non-controlling interests. Enbridge said it is adjusting its distributable cash flow guidance for 2018 to a range of $650 million to $700 million. The previous guidance was a range of $720 million to $770 million.

The NOI and other proceedings address the lower corporate tax rate stemming from the law, a reduction from 35% to 21%, along with accumulated deferred income taxes (ADIT), bonus depreciation that was removed and other issues. The NOI seeks input solely related to ADIT – essentially a pool of money collected by pipelines and utilities in anticipation of paying the Internal Revenue Service – and the exclusion of bonus depreciation. Due to the tax law change, current ADIT balances do not accurately reflect companies’ current tax liability, FERC explained.

ADIT and the bonus depreciation change in the tax law pose challenges for FERC to address in rates, and given the complexity of issues, any new policy pronouncement may not appear until late in 2018 or perhaps early in 2019, said Tezak.

For oil and liquids pipelines that make their Form 6 filings in April, the uncertainty about ADIT treatment could lead to complaints from shippers that a pipeline is overearning, though ClearView believes pipelines could plausibly argue that any April 2018 Form 6 filings for calendar year 2017 could be inaccurate until ADIT is addressed and that shippers have not met FERC’s standard for showing excess earnings. “In other words, the bar to filing complaints has been high to date and looks set to remain high at this time,” Tezak said.

Among the entities that have pushed FERC to address tax reform issues in pipeline rates is the American Public Gas Association (APGA), which said the rulemaking process at FERC – because the NOPR is subject to comments and a final rule that could differ from what is proposed — will delay the rate relief that pipeline customers deserve.

Outside of FERC, APGA said it would call on Congress to pass legislation to address the rate refund disparity between the Federal Power Act (FPA) and the NGA. It made good on that vow with March 22 letters to key lawmakers in the House of Representatives and the Senate. In the letters, APGA President and CEO Bert Kalisch noted that in contrast to the FPA that provides FERC with refund authority based on the date of a customer complaint, NGA Section 5 only provides FERC with the ability to provide prospective rate relief after a finding by the Commission.

That lack of refund authority means that natural gas pipelines have a strong incentive to delay any rate proceeding to provide relief to customers, Kalisch said. He told the chairman and ranking members of the House and Senate energy committees, along with the energy subcommittee of the House Energy and Commerce Committee, that FERC “is effectively hamstrung by Congress’ writing” of NGA Section 5 and a failure to update the law appropriately.

Each month that passes means natural gas consumers fail to see the benefit of the lower corporate tax rate in their pipeline rates, Kalisch said.

As Congress considers comprehensive energy legislation, “we urge you to address Section 5 of the Natural Gas Act and provide natural gas consumers with the same level of protection from overcharges that currently exists for electric consumers,” he told the lawmakers.

In two separate proceedings under NGA Section 5, FERC on March 15 started two investigations to determine whether the rates charged by Dominion Energy Overthrust Pipeline LLC and Midwestern Gas Transmission Co. are just and reasonable. The orders directed Overthrust and Midwestern to file cost and revenue studies within 75 days and called for an administrative law judge (ALJ) to expedite the hearing process.

In the order for Midwestern (RP18-441), a 400-mile pipeline owned by ONEOK Inc., FERC said it reviewed Form 2 information for the years 2015 and 2016 and estimated that Midwestern’s return on equity (ROE) for those years was 15.8% and 16.6%, respectively. With the lower corporate income tax rate passed by Congress in 2017 used in those calculations, the ROE for 2015 and 2016 would have been 19.2% and 20.2%, respectively, FERC said.

For Overthrust, a 261-mile pipeline in Wyoming that connects with other pipelines serving the Rocky Mountain region and downstream markets, FERC estimated that the ROE was 23.4% in 2015 and 19.9% in 2016. Using the revised policy statement’s elimination of an income tax allowance in its cost of service rates, the ROEs for 2015 and 2016 would have been 36.4% and 30.9%, respectively, according to the order (RP18-442).

FERC concluded that a Track II Hearing Timeline is reasonable in both cases, but it adjusted that timeline based on when the cost and revenue studies are due, rather than the date of an order designating a presiding ALJ. Therefore, the initial decision of the ALJs must be issued within 47 weeks of the date the cost and revenue studies are due, according to the orders.

By Tom Tiernan TTiernan@fosterreport.com

[1]   For past stories, see, In NOPR and NOI, FERC Seeks Data to Address Tax Law Changes for Pipelines, Utilities, FR No. 3190, pp. 3-5 and INGAA Says FERC Should Not Grant Broad Tax Relief Sought by Shippers, APGA, FR No. 3184, pp. 21-24.

 

This article appears as published in The Foster Report No. 3191, issued on March 23, 2018

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