|October 24, 2013|
Previously published on October 23, 2013
On October 17, 2013, the Commission issued two orders of significance to the natural gas industry. First, in Opinion No. 528, 145 FERC ¶ 61,040 (Oct. 17, 2013), the Commission issued its Opinion and Order on the Initial Decision in El Paso Natural Gas Company’s (EPNG) rate case. Among other things, the Commission affirmed the Presiding Judge’s rejection of several shipper proposals to require EPNG to share the cost of unsubscribed and discounted capacity. Shippers had argued that the level of unsubscribed capacity and discounting had become so great that requiring captive customers to pay for all costs not recovered due to discounted and unsubscribed capacity was unjust and unreasonable. The Commission found that EPNG’s unsubscribed capacity and discounting was attributable to competition, that the Natural Gas Act “requires the Commission to approve rates that permit a pipeline an opportunity to recover 100 percent of its costs,” and that therefore a full discount adjustment (and recovery of unsubscribed capacity costs) was warranted. This holding represents the first Commission decision on this issue after the 2005 Selective Discounting Policy Order, which left the door open for shippers to argue that pipelines should absorb costs if unsubscribed capacity or discounting cause an undue hardship on captive customers.
In what may be viewed as a change in policy, however, the Commission also held that costs must be allocated among zones based on unadjusted billing determinants. Unless reversed on rehearing, this ruling will have the effect of requiring the costs of discounts to be allocated solely to the zones where the discounts were given, instead of being spread across the system. Finally, of note, in the first litigated case resolving the design of hourly service rates, the Commission approved EPNG’s rate design based on the Equitable method of dividing costs between a capacity and deliverability component and applying premium factors based on the hourly variability of each service to the deliverability component. The Commission recognized that “the hourly services proposed by El Paso in this case are designed, in part, to support gas-electric coordination”, and that “[p]roviding flexible hourly services furthers this stated policy objective.”
Second, in Tennessee Gas Pipeline Company, L.L.C, 145 FERC ¶ 61.058 (Oct. 17. 2013), the Commission approved Tennessee’s proposal to provide a scheduling priority for within-the-path secondary receipt to primary delivery points over the objections of parties contending that the proposal discriminated against primary receipt to secondary deliveries. The Commission found Tennessee could reasonably conclude that there is a greater need for gas to be delivered to a primary delivery point where gas is put to a specific end use and the shipper has no ability to move its delivery point. The Commission noted that with added assurance that end-use deliveries are less likely to be curtailed, long-haul shippers are encouraged to retain their long-haul contracts instead of moving their primary receipts to shale supply regions.
In addition to the EPNG and Tennessee orders, last month the FERC issued two orders that offer helpful guidance for conversions of under-utilized natural gas pipeline facilities to oil service. With the decline in demand for natural gas transportation service in some parts of the country due to the proliferation of shale gas and the concomitant increase in demand for transportation to move emerging oil supplies, several pipelines have proposed or considered the conversion of gas pipeline facilities to oil transmission. In Tallgrass Interstate Gas Transmission, LLC, 144 FERC ¶ 61,197 (Sept. 12, 2013), the Commission approved Tallgrass’ request to abandon several hundred miles of pipeline and convert the facilities to crude oil transportation. Tallgrass involved a 432-mile segment of its 804-mile “Pony Express Pipeline”, which had been converted from oil to natural gas service in the 1990’s. While the facility had experienced diminishing gas throughput in the past several years, demand for crude oil transportation, driven by Bakken production, had strengthened greatly.
Recognizing that a primary consideration in determining whether to approve a proposed abandonment of gas facilities is “continuity and stability of existing service”, Tallgrass proposed to meet its existing gas service requirements after the abandonment by constructing replacement-type facilities and obtaining firm transportation capacity on other interstate pipelines. To keep Tallgrass’ existing customers whole, the affiliated purchaser of the facilities to be converted to oil use agreed to reimburse Tallgrass for the cost of the replacement facilities and transportation arrangements on other pipelines for a period of between five to ten years. In approving the abandonment, the Commission rejected the argument that the quality of the replacement service to existing shippers would be inferior, finding that the existing shippers would have access to secondary receipt points and supply on the third-party pipelines. The Commission also rejected the contention that the five to ten year reimbursement commitment for the third-party capacity was not adequate.
In the second case, Missouri Interstate Gas, LLC, Opinion No. 525-A, 144 FERC ¶ 61,220 (Sept. 19, 2013), the Commission, following a court remand, affirmed its earlier opinion allowing a gas pipeline to include in rate base an “acquisition premium” associated with a purchase of an oil pipeline converted to gas. An acquisition premium reflects the excess of the purchase price over the facility’s depreciated original cost, or net book value. In approving the inclusion of the premium, the Commission clarified the “substantial benefits” test used to determine whether such inclusion by an oil or gas pipeline is appropriate.
The substantial benefits test, which the Commission applies in both gas and oil cases, requires a pipeline claiming an acquisition premium to meet a two-prong test: First, the pipeline must show that the assets either will be placed in FERC-jurisdictional service for the first time or put to a new use, such as when facilities are converted from one utility service to another. The facilities, having been converted from oil to gas, met the first prong. The second prong requires that the acquisition provide substantial, quantifiable benefits to ratepayers even if the full purchase price, including the portion above depreciated original cost, is included in rate base.
The second prong was the issue in Missouri Gas. Specifically, a major issue was whether the pipeline was required to show “specific dollar benefits resulting from the sale”, in addition to showing that the purchase price was less than the cost of constructing a comparable facility. FERC held that, despite language in the court remand that had listed specific dollar benefits as a separate element of the test, the second prong was met upon a showing that the purchase price was lower than the cost of constructing a new facility, which would result in lower rates for ratepayers. By conflating these two elements, this opinion may make it easier for oil and gas pipelines to include acquisition premiums in conversion cases. Notably, the Commission concluded that its ruling will provide appropriate incentives for jurisdictional companies to purchase and utilize existing facilities in lieu of constructing new facilities, thereby avoiding unnecessary construction and attendant environmental impacts.