Regulatory Matters	12 Months Ended
Oct. 31, 2011
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 states address our gas supply hedging activities. Additionally, North Carolina and South Carolina 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. In Tennessee, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings; if the difference is greater, there would be a charge to customers through the ACA filing. North Carolina Jurisdiction 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, $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, 2011 and 2010, we had unamortized balances of $7.7 million and $8.3 million, respectively. With the inception of our North Carolina energy conservation program on November 1, 2005, we incurred charges of $6.4 million for the benefit of residential and commercial customers. The charges consisted of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.4 million for interest accruals on the conservation funding and reduction of customer rates. At October 31, 2010, we had a liability for the conservation programs of $.4 million and no liability as of October 31, 2011. 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, 2011 that is subject to a future rate proceeding is $8 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 August 2011, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2011. A hearing on this matter was held on October 4, 2011. We are unable to predict the outcome of this proceeding at this time. 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 and January 2011 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” as agreed to by us and the North Carolina Public Staff. South Carolina Jurisdiction 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 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 2009, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2009 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 2008 order. In October 2009, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.1 million annual increase in margin based on a return on equity of 11.2%, effective November 1, 2009. 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 the October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the ORS, the SCEUC 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, the SCEUC 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 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 2009, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2009. 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 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. 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. At the PSCSC's request, the ORS held a public briefing in November 2011 on the issue of how to measure the prudence of hedging programs in future annual review proceedings with no action taken on the matter. 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 Jurisdiction In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the 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 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 December 2008, we filed an annual report for the twelve months ended December 31, 2007 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In April 2009, the TRA staff filed its final audit report, with which we concurred. In May 2009, the TRA issued an order adopting all findings from the staff audit. The order included cost of gas adjustments for the calendar year 2007 review period. There was no material impact from these gas cost adjustments on our financial position, results of operations or cash flows. We were found to be in compliance with the TRA rules in the use of the ACA mechanism. 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 October 2010, the TRA issued its order adopting the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report. In December 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA that reflected 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 issued an order approving the deferred gas cost account. 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. We are unable to predict the outcome of this proceeding at this time. 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. We are unable to predict the outcome of this proceeding 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 the current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes are proposed to be effective March 1, 2012. A hearing on this matter has been scheduled for the week of January 23, 2012. We are unable to predict the outcome of this proceeding at this time. 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 deny recovery of $1.5 million for us. 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 operations and maintenance expenses. In November 2011, we filed for reconsideration, which was granted on November 21, 2011. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows. In September 2010, we filed a petition with the TRA requesting deferred accounting treatment for the direct, incremental expenses incurred as a result of our response to the severe flooding in Nashville in May 2010. The TRA approved our petition in October 2010. The balance in the deferred account is $1 million as of October 31, 2011 and 2010. We are seeking recovery of these deferred expenses in the general rate application filed with the TRA in September 2011. All Jurisdictions Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when available. 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, 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. In all three jurisdictions for the twelve months ended October 31, 2009, we generated $46 million of margin from secondary market activity, $34.5 million which is allocated to customers as gas cost reductions and $11.5 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, 2011

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 states address our gas supply hedging activities. Additionally, North Carolina and South Carolina 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. In Tennessee, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings; if the difference is greater, there would be a charge to customers through the ACA filing.

North Carolina Jurisdiction

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, $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, 2011 and 2010, we had unamortized balances of $7.7 million and $8.3 million, respectively.

With the inception of our North Carolina energy conservation program on November 1, 2005, we incurred charges of $6.4 million for the benefit of residential and commercial customers. The charges consisted of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.4 million for interest accruals on the conservation funding and reduction of customer rates. At October 31, 2010, we had a liability for the conservation programs of $.4 million and no liability as of October 31, 2011.

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, 2011 that is subject to a future rate proceeding is $8 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 August 2011, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2011. A hearing on this matter was held on October 4, 2011. We are unable to predict the outcome of this proceeding at this time.

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 and January 2011 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” as agreed to by us and the North Carolina Public Staff.

South Carolina Jurisdiction

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 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 2009, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2009 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 2008 order. In October 2009, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.1 million annual increase in margin based on a return on equity of 11.2%, effective November 1, 2009.

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 the October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the ORS, the SCEUC 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, the SCEUC 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 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 2009, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2009.

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 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.

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. At the PSCSC's request, the ORS held a public briefing in November 2011 on the issue of how to measure the prudence of hedging programs in future annual review proceedings with no action taken on the matter.

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 Jurisdiction

In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the 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 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 December 2008, we filed an annual report for the twelve months ended December 31, 2007 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In April 2009, the TRA staff filed its final audit report, with which we concurred. In May 2009, the TRA issued an order adopting all findings from the staff audit. The order included cost of gas adjustments for the calendar year 2007 review period. There was no material impact from these gas cost adjustments on our financial position, results of operations or cash flows. We were found to be in compliance with the TRA rules in the use of the ACA mechanism.

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 October 2010, the TRA issued its order adopting the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report.

In December 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA that reflected 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 issued an order approving the deferred gas cost account.

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. We are unable to predict the outcome of this proceeding at this time.

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. We are unable to predict the outcome of this proceeding 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 the current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes are proposed to be effective March 1, 2012. A hearing on this matter has been scheduled for the week of January 23, 2012. We are unable to predict the outcome of this proceeding at this time.

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 deny recovery of $1.5 million for us. 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 operations and maintenance expenses. In November 2011, we filed for reconsideration, which was granted on November 21, 2011. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.

In September 2010, we filed a petition with the TRA requesting deferred accounting treatment for the direct, incremental expenses incurred as a result of our response to the severe flooding in Nashville in May 2010. The TRA approved our petition in October 2010. The balance in the deferred account is $1 million as of October 31, 2011 and 2010. We are seeking recovery of these deferred expenses in the general rate application filed with the TRA in September 2011.

All Jurisdictions

Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when available. 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, 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. In all three jurisdictions for the twelve months ended October 31, 2009, we generated $46 million of margin from secondary market activity, $34.5 million which is allocated to customers as gas cost reductions and $11.5 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.