Regulatory Matters

Rate-Regulated Basis of Accounting

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2015 and 2014 are as follows.



In thousands	2015		2014
Regulatory Assets:
Current:
Unamortized debt expense on reacquired debt	$	238	$	239
Amounts due from customers	—		16,108
Environmental costs	1,513		1,568
Deferred operations and maintenance expenses	847		916
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,769
Robeson LNG development costs	381		917
Other	1,730		1,850
Total current	10,936		27,837

Noncurrent:
Unamortized debt expense on reacquired debt	4,666		4,904
Environmental costs	5,107		6,470
Deferred operations and maintenance expenses	3,997		4,721
Deferred pipeline integrity expenses	29,824		24,694
Deferred pension and other retirement benefits costs	17,861		18,799
Amounts not yet recognized as a component of pension and other retirement benefit costs	114,854		94,265
Regulatory cost of removal asset	19,087		18,275
Robeson LNG development costs	127		509
Other	1,203		1,644
Total noncurrent	196,726		174,281
Total	$	207,662	$	202,118



Regulatory Liabilities:
Current:
Amounts due to customers	$	13,367	$	46,231

Noncurrent:
Regulatory cost of removal obligations	521,478		506,574
Deferred income taxes	68,738		51,930
Amounts not yet recognized as a component of pension and other retirement benefit costs	85		94
Total noncurrent	590,301		558,598
Total	$	603,668	$	604,829

The 2014 presentation of unamortized debt expense has been changed to conform with the current year presentation in the table above. As discussed in Note 1 to the consolidated financial statements, we early adopted ASU 2015-03 requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt. Consequently, unamortized debt expense of $.9 million current and $9 million noncurrent presented in 2014 as regulatory assets have been reclassified as a reduction of $9.9 million to the carrying value of long-term debt. The amounts presented above in line items "Unamortized debt expense on reacquired debt" represent unamortized debt expense associated with the early retirement or the refunding of debt in accordance with established regulatory practice. Unamortized debt expenses related to short-term bank debt and unallocated expenses of our open debt and equity shelf registration are now presented in the line item "Other noncurrent assets" as "Noncurrent Assets" in the Consolidated Balance Sheets. See Note 1 with discussion of "Unamortized Debt Expense" and Note 5 to the consolidated financial statements for related discussion of these presentation changes.

As of October 31, 2015, we have $19.1 million of AROs and $117 million of other regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the TRA on a deferred cash basis.

Regulatory Oversight and Rate and Regulatory Actions

Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.

The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.

North Carolina

The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.

The NCUC had allowed EasternNC to defer its O&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9 million at October 31, 2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 6.55% per annum with amortization beginning January 1, 2014 over an 82-month period ending October 31, 2020. As of October 31, 2015 and 2014, we had unamortized balances, including accrued interest, of $4.8 million and $5.6 million, respectively.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to certain incremental pipeline integrity external expenditures beginning November 1, 2004. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding discussed below was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2015 and 2014, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $33.3 million and $28.2 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs is expected to continue until another recovery mechanism is established in a future rate proceeding.

With the approval of the settlement of the 2013 NCUC general rate proceeding discussed below, certain capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR, as revised by a subsequent settlement approved by the NCUC in November 2015. The settlement also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018.

In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Our gas costs have never been disallowed on the basis of prudence.

In November 2013, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2013. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range up to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued November 2013, November 2014 and November 2015 found our hedging activities during the review periods to be reasonable and prudent.

In April 2013, we withdrew a petition that had been filed with the NCUC in October 2012 requesting authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, citing our intent to address the matter in a general rate application. The balance in “Plant held for future use” was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. The appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.

In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:


•	Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10% and an overall rate of return of 7.51%.


•	Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.


•	Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.


•	Implementation of lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.


•	Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.


•	Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.


•	Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.


•	Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.

In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provided for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. In February 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR:


•	Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31.


•	Extension of the IMR tariff from October 31, 2017 to October 31, 2019.


•	An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings.


•	Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case:


•	Transmission integrity: 85% IMR / 15% rate case.


•	Distribution integrity: 90% IMR / 10% rate case.


•	Right-of-way clearing for integrity projects: 15% IMR / 85% rate case.


•	Work and asset management system: 68% IMR / 32% rate case.


•	Tax-related adjustments.


•	An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015.

Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $13.4 million in annual IMR margin revenues, effective December 1, 2015, based on $161.9 million of IMR-eligible capital investments in integrity and safety projects over the eleven-month period ended September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase.

In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the NCUC Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014, the NCUC issued an order rejecting the joint stipulation of settlement, finding that we must bill our customers for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further required us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.

In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. For further information on this shelf registration statement, see Note 5 to the consolidated financial statements.

In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina. In March 2015, the NCUC issued an order approving our request. The bill credit of $45.5 million was reflected on customers' April 2015 bills, reducing amounts due to customers in North Carolina.

South Carolina

We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in October 2011. In October 2012, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a stipulated return on equity of 11.3%, effective November 1, 2012.

In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in October 2012. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $.1 million annual decrease in margin based on a stipulated return on equity of 11.3%, effective November 1, 2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.

In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in October 2013. In October 2014, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina as discussed above, both with amortization periods of one year beginning November 2014 and ending October 2015.

In June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2015.

In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range up to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates. In an August 2011 order, the PSCSC approved a stipulation that our hedging program should no longer have a required minimum volume of hedging.

In August 2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2013.

In August 2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2014.

In September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015.

In July 2014, we filed a petition with the PSCSC requesting a limited waiver of certain billing provisions of our tariff related to emergency service for customers in January 2014. In August 2014, the PSCSC granted our request and ordered us to continue to collaborate with the ORS to revise our tariff to address the situation that led to this petition.

Tennessee

In Tennessee, we operate under the Tennessee Incentive Plan (TIP) that benchmarks gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. Under the TIP, the TRA established an allocation of secondary marketing gains and losses to ratepayers and shareholders with a uniform 75/25 sharing ratio with a $1.6 million annual incentive cap for us on these gains and losses. The TIP includes procedures for asset management transactions and provides for a triennial review of TIP operations by an independent consultant. Although the TIP replaced annual prudence reviews of our gas purchasing activities, we undergo an annual compliance audit on the accuracy of our calculations and compliance with all TRA orders and directives regarding the calculation of our deferred gas cost account balances under the Actual Cost Adjustment (ACA) mechanism.

In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2013, the TRA approved the TIP account balances and issued its written order approving our TIP account balances.

In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under the TIP. In February 2014, the Audit Staff submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.

In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. In March 2015, the Audit Staff submitted their report with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report. The TRA's written order was issued in May 2015.

In August 2015, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2015 under the TIP. We are waiting on a ruling from the TRA at this time.

In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2013, the TRA approved the deferred gas cost account balances and issued its written order.

In August 2013, we filed a petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the ACA annual report filed in December 2014 for the twelve-month period ended June 30, 2013. In January 2015, the TRA issued its written order approving the settlement agreement. In October 2015, the TRA approved the deferred gas cost account balances for the twelve-month period ended June 30, 2013 and issued its written order.

In November 2015, we filed an annual report for the twelve months ended June 30, 2014 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, proposed to be effective March 1, 2012. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. In December 2011, we and the CAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA issued its written order in April 2012.

As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for deferred accounting treatment in October 2010. These deferred expenses are being amortized over eight years beginning March 1, 2012 through February 2020.

In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures of $100.4 million incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the CAD filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015. In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016. We are waiting on the TRA's written order at this time.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we will begin refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. We are waiting on the TRA's written order at this time.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a regulated service. The TRA's written order was issued in October 2015.

All States

Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2015, 2014 and 2013 is presented below.



In millions	2015		2014		2013
Allocated to customers as gas cost reductions	$	60.1	$	72.2	$	26.9
Margin allocated to us	21.1		25.4		9.0
Margin from secondary market activity	$	81.2	$	97.6	$	35.9

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.