Regulatory Matters	12 Months Ended
Oct. 31, 2012
Regulatory Matters Disclosure [Abstract]
Public Utilities Disclosure Text Block	2. Regulatory Matters 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 operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. The deferred amounts accrued interest at a rate of 8.69% 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. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005 of $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred operations and maintenance expenses was $9 million at October 31, 2008. This balance is accruing interest at a rate of 7.84% per annum and is being amortized over a twelve year period. As of October 31, 2012 and 2011, we had unamortized balances of $7 million and $7.7 million, respectively. We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the operations and maintenance costs applicable to all incremental expenditures beginning November 1, 2004. Under the settlement of the 2008 general rate proceeding, the pipeline integrity management costs incurred between July 1, 2005 and June 30, 2008 of $4.6 million were fully amortized over a three-year period beginning November 1, 2008. The existing regulatory asset treatment for ongoing pipeline integrity management costs continues until another recovery mechanism is established in a future rate proceeding. The unamortized balance as of October 31, 2012 that is subject to a future rate proceeding is $20.3 million; we have a recorded regulatory asset for deferred pipeline integrity expenses of $13.7 million. In North 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. In February 2010, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2009, with adjustments agreed to by us as a result of the North Carolina Public Staff's audit of the 2009 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. In January 2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2010, with adjustments agreed to by us as a result of the North Carolina Public Staff's audit of the 2010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the North Carolina Public Staff's audit of the 2011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. 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 some level of protection against significant price increases, targets a percentage range of 22.5% 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 February 2010, January 2011, January 2012 and November 2012 found our hedging activities during the review periods to be reasonable and prudent. As part of the February 2010 order, the NCUC approved an adjustment of $1.1 million related to hedging activity that decreased “Amounts due from customers” in “Current Assets” in the Consolidated Balance Sheets as agreed to by us and the North Carolina Public Staff. In October 2012, we filed a petition seeking authority to transfer $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, effective November 1, 2012. This balance in “Plant held for future use” relates to the development of the LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. We are waiting on a ruling by the NCUC on this matter. We are unable to predict the outcome of this proceeding at this time. South Carolina We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South Carolina. If a utility elects to operate under the RSA, 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 2010, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2010 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in an October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS) and us that resulted in a $.75 million annual increase in margin on a return on equity of 11.3%, effective November 1, 2010. In June 2011, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the ORS and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of 11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service, effective November 1, 2011. 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 the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012. 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. In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2010. 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 of 22.5% 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 February 2011, the ORS requested that the PSCSC temporarily suspend the PSCSC-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of the hedging program was requested to be effective prospectively upon the issuance of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing protection policies. In March 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of price stability for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC in April 2011. In June 2011, the ORS withdrew its petition for suspension of gas hedging programs. In July 2011, the PSCSC granted the ORS' motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings. Because the PSCSC has provided no further guidance, we will address future gas hedging activities in our annual gas cost proceedings to determine the prudence of our gas purchases. In August 2011, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated that our hedging program should no longer have a required minimum volume of hedging. In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012. In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy efficiency programs to residential and commercial customers at a total annual cost of $.35 million. The proposed programs in South Carolina were designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs through annual RSA filings and were similar to approved energy efficiency programs in North Carolina. In May 2010, the PSCSC approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers. Tennessee In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant. In July 2009, we filed an annual report for the twelve months ended December 31, 2008 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. There was no material impact from these gas cost adjustments to our financial position, results of operations or cash flows. In August 2010, the TRA adopted the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report. The TRA issued its written order approving the deferred gas cost balances in October 2010. In December 2010, we filed our report with the TRA for the eighteen months ended June 30, 2010 reflecting the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA approved the deferred gas cost account balances and issued its written order. In September 2010, 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, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances. In August 2011, 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, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012. In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012. 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. 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. 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 for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above then current annual revenues. 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. The changes were proposed to be effective March 1, 2012. In December 2011, we and the Consumer Advocate and Protection Division 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 then 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's written order was issued 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 8 years beginning March 1, 2012. In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in operations and maintenance expenses. The written order was issued by the TRA in June 2012. 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 amended 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. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2010, we generated $42.8 million of margin from secondary market activity, $32.1 million of which is allocated to customers as gas cost reductions and $10.7 million as margin allocated to us. We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas into our system in order to mitigate the risk exposure to the financial condition of the marketers.

Regulatory Matters

12 Months Ended

Oct. 31, 2012

Regulatory Matters Disclosure [Abstract]

2. Regulatory Matters

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 operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. The deferred amounts accrued interest at a rate of 8.69% 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. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005 of $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred operations and maintenance expenses was $9 million at October 31, 2008. This balance is accruing interest at a rate of 7.84% per annum and is being amortized over a twelve year period. As of October 31, 2012 and 2011, we had unamortized balances of $7 million and $7.7 million, respectively.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the operations and maintenance costs applicable to all incremental expenditures beginning November 1, 2004. Under the settlement of the 2008 general rate proceeding, the pipeline integrity management costs incurred between July 1, 2005 and June 30, 2008 of $4.6 million were fully amortized over a three-year period beginning November 1, 2008. The existing regulatory asset treatment for ongoing pipeline integrity management costs continues until another recovery mechanism is established in a future rate proceeding. The unamortized balance as of October 31, 2012 that is subject to a future rate proceeding is $20.3 million; we have a recorded regulatory asset for deferred pipeline integrity expenses of $13.7 million.

In North 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.

In February 2010, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2009, with adjustments agreed to by us as a result of the North Carolina Public Staff's audit of the 2009 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In January 2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2010, with adjustments agreed to by us as a result of the North Carolina Public Staff's audit of the 2010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the North Carolina Public Staff's audit of the 2011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. 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 some level of protection against significant price increases, targets a percentage range of 22.5% 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 February 2010, January 2011, January 2012 and November 2012 found our hedging activities during the review periods to be reasonable and prudent. As part of the February 2010 order, the NCUC approved an adjustment of $1.1 million related to hedging activity that decreased “Amounts due from customers” in “Current Assets” in the Consolidated Balance Sheets as agreed to by us and the North Carolina Public Staff.

In October 2012, we filed a petition seeking authority to transfer $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, effective November 1, 2012. This balance in “Plant held for future use” relates to the development of the LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. We are waiting on a ruling by the NCUC on this matter. We are unable to predict the outcome of this proceeding at this time.

South Carolina

We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South Carolina. If a utility elects to operate under the RSA, 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 2010, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2010 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in an October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS) and us that resulted in a $.75 million annual increase in margin on a return on equity of 11.3%, effective November 1, 2010.

In June 2011, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the ORS and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of 11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service, effective November 1, 2011.

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 the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012.

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.

In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2010.

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 of 22.5% 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 February 2011, the ORS requested that the PSCSC temporarily suspend the PSCSC-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of the hedging program was requested to be effective prospectively upon the issuance of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing protection policies. In March 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of price stability for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC in April 2011. In June 2011, the ORS withdrew its petition for suspension of gas hedging programs. In July 2011, the PSCSC granted the ORS' motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings. Because the PSCSC has provided no further guidance, we will address future gas hedging activities in our annual gas cost proceedings to determine the prudence of our gas purchases.

In August 2011, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated that our hedging program should no longer have a required minimum volume of hedging.

In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.

In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy efficiency programs to residential and commercial customers at a total annual cost of $.35 million. The proposed programs in South Carolina were designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs through annual RSA filings and were similar to approved energy efficiency programs in North Carolina. In May 2010, the PSCSC approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers.

Tennessee

In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.

In July 2009, we filed an annual report for the twelve months ended December 31, 2008 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. There was no material impact from these gas cost adjustments to our financial position, results of operations or cash flows. In August 2010, the TRA adopted the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report. The TRA issued its written order approving the deferred gas cost balances in October 2010.

In December 2010, we filed our report with the TRA for the eighteen months ended June 30, 2010 reflecting the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA approved the deferred gas cost account balances and issued its written order.

In September 2010, 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, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances.

In August 2011, 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, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.

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. 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. 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 for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above then current annual revenues. 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. The changes were proposed to be effective March 1, 2012. In December 2011, we and the Consumer Advocate and Protection Division 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 then 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's written order was issued 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 8 years beginning March 1, 2012.

In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in operations and maintenance expenses. The written order was issued by the TRA in June 2012.

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 amended 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. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2010, we generated $42.8 million of margin from secondary market activity, $32.1 million of which is allocated to customers as gas cost reductions and $10.7 million as margin allocated to us.

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