Regulatory Matters |
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| Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Regulatory Matters | Regulatory Matters Regulatory Assets and Liabilities Current and noncurrent regulatory assets and liabilities were comprised of the following items:
No regulatory assets are earning a return on investment at December 31, 2015. Regulatory assets of $7.2 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to 7 years. Assets: Unrecognized pension benefit and other postretirement benefit costs – In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders to be recovered through base rates. Other postretirement costs – Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms. Deferred taxes on AFUDC equity - ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. The Partnership is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly-owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized. The regulatory asset was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level. Liabilities: Cost of removal - Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of some rate-regulated subsidiaries for future costs to be incurred. Regulatory effects of accounting for income taxes - Represents amounts related to state income taxes collected at a higher rate than the current statutory rates assumed in rates, which is being amortized to earnings in association with depreciation on related property. The regulatory liability was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level. Unrecognized pension benefit and other postretirement benefit costs - In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the benefits as a regulatory liability in accordance with regulatory orders. Other postretirement costs - Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in the Partnership’s results, which exceeds the amount funded in the plan. Regulatory Matters Columbia Gas Transmission Customer Settlement. On January 24, 2013, the FERC approved the Settlement. In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately $1.5 billion over a five-year period, which began in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter. The Settlement also provided for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately $25.0 million in revenues annually thereafter. The Settlement includes a CCRM, a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission's long-term plan to modernize its interstate transmission system. The CCRM provides for a 14.0% revenue requirement with a portion designated as a recovery of taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission the opportunity to recover its revenue requirement associated with a $1.5 billion investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with $100.0 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15.0% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term. On January 28, 2016, Columbia Gas Transmission received FERC approval of its December 2015 filing to recover costs associated with the third year of its comprehensive system modernization program. Total program adjusted spend to date is $937.1 million. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. In December 2015, Columbia Gas Transmission filed an extension of this settlement and has requested FERC’s approval of the customer agreement by March 31, 2016. Columbia Gulf. On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the NGA to determine whether Columbia Gulf ’s existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf intends to file a cost and revenue study with FERC on April 5, 2016, as required by the January 21 Order. The January 21 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by February 28, 2017. The outcome of this proceeding to Columbia Gulf is not currently determinable. Cost Recovery Trackers and other similar mechanisms. Under section 4 of the NGA, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. A significant portion of our revenues and expenses are related to the recovery of costs under these tracking mechanisms. The associated costs for which we are obligated are reported in operating expenses with the offsetting recoveries reflected in revenues. These costs include: third-party transportation, electric compression, and certain approved operational purchases of natural gas. The tracking of certain environmental costs ended in 2015. Additionally, we recover fuel for company used gas and lost and unaccounted for gas through in-kind trackers where a retainage rate is charged to each customer to collect fuel. The recoveries and costs are both reflected in operating expenses. |
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