REGULATORY ENVIRONMENT	9 Months Ended
Sep. 30, 2013
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Wisconsin 2014 Rate Case In March 2013, WPS filed an application with the PSCW to increase retail electric and natural gas rates $71.1 million and $19.0 million, respectively, with rates proposed to be effective January 1, 2014. The filing includes a request for a 10.75% return on common equity and a common equity ratio of 51.11% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the purchase and operation of the Fox Energy Center, the completion of a one-time fuel refund to customers in 2013, increased electric transmission costs, additional construction related to the installation of environmental controls and the improvement of electric reliability, the recovery of pension and other employee benefit costs deferred in 2013 rates, and general inflation. Partially offsetting these increases are lower purchased power capacity costs and a refund to customers resulting from WPS's decoupling mechanism. The proposed retail natural gas rate increase is generally the result of the recovery of amounts related to decoupling, increased costs of inspecting natural gas lines for safety, the recovery of pension and other employee benefit costs deferred in 2013 rates, and general inflation. In August 2013, the PSCW Staff submitted testimony and recommended rate increases of $9.3 million and $7.8 million for retail electric and natural gas, respectively, reflecting a 10.20% return on common equity. Their recommendation also included a common equity ratio of 50.14% in WPS's regulatory capital structure. The PSCW held both technical and public hearings in September 2013. In October 2013, WPS issued an initial brief revising its requested retail electric and natural gas rate increases to approximately $60 million and approximately $14 million, respectively, including a reduced return on common equity of 10.60%. Included in these revised amounts, is WPS's request for recovery of $1.7 million for the Wisconsin retail allocation of environmental remediation capital and operating costs related to WPS's Consent Decree with the EPA. See Note 12, "Commitments and Contingencies," for more information. Finally, WPS requested the removal of the annual caps associated with the decoupling mechanism that is currently in place. WPS's revised request is a result of WPS's current position on contested issues. New rates are expected to be effective January 1, 2014. 2013 Rates In December 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement included a $28.5 million imputed retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase is being deferred for recovery in a future rate proceeding. As a result, there was no change to customers' 2013 retail electric rates. The settlement agreement also included a $3.4 million retail natural gas rate decrease, which included a deferral of $2.1 million of pension and other employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were reduced based on updated December 31, 2012, pension and other employee benefit cost estimates, which were filed with the PSCW in March 2013. The settlement agreement reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The settlement agreement also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. Lastly, the settlement agreement authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek Wind Project. A new decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism is based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism does not cover all customer classes, and it continues to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate proceeding. 2012 Rates In December 2011, the PSCW issued a final written order for WPS, effective January 1, 2012. It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million. The electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% price variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs. Michigan 2014 MGU Rate Case In October 2013, MGU entered into a settlement agreement with the MPSC and all other involved parties resolving all issues in the MGU 2014 rate case. The settlement agreement provides for a retail natural gas rate increase of $4.5 million, effective January 1, 2014. The rates reflect a 10.25% return on common equity and a common equity ratio of 48.62% in MGU's regulatory capital structure. Additionally, the order requires MGU to terminate its existing decoupling mechanism, effective December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminates MGU's existing uncollectible expense true-up mechanism after December 31, 2013. MGU Depreciation Case In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in the first quarter of 2013. In June 2013, the MPSC issued an order related to MGU's most recent depreciation case. This order also approved a settlement agreement reflecting recovery of these previously disallowed costs. 2014 UPPCO Rate Case In June 2013, UPPCO filed an application with the MPSC to increase retail electric rates $7.9 million. Interim rates could be effective on January 1, 2014. UPPCO's request reflects a 10.75% return on common equity and a common equity ratio of 54.98% in its regulatory capital structure. The request was primarily driven by capital investments associated with FERC mandated replacements and upgrades of hydroelectric facilities, and increased costs associated with uncollectibles expense, line clearance, system losses, and general inflation. UPPCO is also requesting authority from the MPSC to implement a revenue adjustment mechanism that operates similar to a decoupling mechanism. 2012 UPPCO Rates In December 2011, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $4.2 million, effective January 1, 2012. The new rates reflect a 10.20% return on common equity and a common equity ratio of 54.90% in its regulatory capital structure. The order stated that if UPPCO filed a rate case in 2013, the earliest effective date for new final rates or self-implemented rates would be January 1, 2014. Additionally, the order required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2013. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. It includes an annual 1.5% cap based on distribution revenues approved in the rate case. UPPCO had no decoupling mechanism in place during 2012. In April 2012, the State of Michigan Court of Appeals ruled in a Detroit Edison proceeding that the MPSC did not have authority to approve electric decoupling mechanisms. This decision was not appealed. As a result of this ruling, UPPCO expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery. However, in August 2012, the MPSC issued an order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement. Therefore, in the third quarter of 2012, UPPCO reversed the $1.5 million previously expensed in the first quarter of 2012. Illinois Qualifying Infrastructure Plant (QIP) Rider In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives PGL a cost recovery mechanism for Illinois natural gas infrastructure upgrades that will be collected through a surcharge on customer bills. Later in July 2013, the ICC adopted emergency rules to implement the law. The ICC also opened a docket to develop permanent rules, which will replace the emergency rules. This Act eliminates a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation once PGL obtains an infrastructure tariff. In September 2013, PGL filed with the ICC requesting the proposed rider. The ICC must act no later than January 17, 2014. The ICC may modify the rider only to ensure compliance with the law. The rider would take effect on January 1 of the year in which the ICC issues its order. 2013 Rates In June 2013, the ICC issued a final order authorizing a retail natural gas rate increase of $57.2 million for PGL and $6.6 million for NSG, effective June 27, 2013. The rates for PGL reflect a 9.28% return on common equity and a common equity ratio of 50.43% in its regulatory capital structure. The rates for NSG reflect a 9.28% return on common equity and a common equity ratio of 50.32% in its regulatory capital structure. The rate order also allows PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Appellate Court (Court). In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG had asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors have requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. If the deferred tax asset created by the 2012 tax NOL is excluded from rate base or the corrections requested by PGL and NSG are not made, there is a potential that the federal income tax "normalization" rules could be violated. These rules specify that the benefit of claiming accelerated depreciation for federal income tax purposes cannot be given to customers before the tax cash flow is received by the company. Once received, the benefit must be given to customers over the useful life of the underlying property. A violation could cause PGL and NSG to lose the ability to claim accelerated depreciation deductions for income tax purposes. We believe this outcome is unlikely. 2012 Rates In January 2012, the ICC issued a final order authorizing a retail natural gas rate increase of $57.8 million for PGL and $1.9 million for NSG, effective January 21, 2012. The rates for PGL reflected a 9.45% return on common equity and a common equity ratio of 49.00% in PGL's regulatory capital structure. The rates for NSG reflected a 9.45% return on common equity and a common equity ratio of 50.00% in NSG's regulatory capital structure. The rate order also approved a permanent decoupling mechanism. The Illinois Attorney General and Citizens Utility Board appealed to the Court the ICC's authority to approve PGL's and NSG's decoupling mechanism and filed a motion to stay the implementation of the permanent decoupling mechanism or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanism subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG had established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanism. As a result, the reserves recorded in 2012 were reversed in the first quarter of 2013. PGL's and NSG's permanent decoupling mechanism is in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to appeal the Court's decision. The Illinois Supreme Court granted the request in September 2013. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse Illinois Supreme Court decision. Between April 1, 2013 and December 31, 2013, PGL and NSG expect to recover $14.8 million and $1.7 million, respectively, related to their 2012 decoupling mechanisms. As of September 30, 2013, PGL and NSG have recovered $6.4 million and $0.8 million, respectively, related to the 2012 decoupling mechanisms. Minnesota 2014 Rate Case In September 2013, MERC filed an application with the MPUC to increase retail natural gas distribution rates by $14.2 million. Interim rates could be effective on January 1, 2014. MERC's request reflects a 10.75% return on common equity and a common equity ratio of 50.31% in its regulatory capital structure. The request was primarily driven by general inflation, property taxes, improvements to customer service programs, efforts to expand the customer base which would have a positive rate effect in the future, and operating and maintenance projects to ensure reliability and safety for customers. 2011 Rates In July 2012, the MPUC approved a written order for MERC authorizing a retail natural gas rate increase of $11.0 million, effective January 1, 2013. The new rates reflect a 9.70% return on common equity and a common equity ratio of 50.48% in its regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap. Federal Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they would no longer receive due to this rate elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) be put into place. Load-serving entities paid these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006. Integrys Energy Services initially expensed the majority of the total $19.2 million of billings paid during the transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC's SECA order and the transmission owners' FERC-ordered compliance filings. Integrys Energy Services protested the FERC’s SECA order, and through various rulings, ultimately received adverse decisions on most substantive issues. Integrys Energy Services appealed the adverse FERC decisions to the U.S. Court of Appeals for the D.C. Circuit. In January 2013, Integrys Energy Services reached a settlement on all remaining issues with American Electric Power Service Corporation (AEP), the transmission owner affected the most from SECA payments collected from Integrys Energy Services. The parties filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC in January 2013. In July 2013, the FERC issued an order approving the uncontested Settlement Agreement. In September 2013, AEP made a lump sum payment of $9.5 million to Integrys Energy Services in complete settlement of the matters at issue (which included a $3.8 million receivable previously recorded). As a result, Integrys Energy Services recorded $5.7 million in other income, representing the portion of the $9.5 million settlement not previously recognized. In September 2013, Integrys Energy Services withdrew its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit, as discussed above.

REGULATORY ENVIRONMENT

Wisconsin

2014 Rate Case

In March 2013, WPS filed an application with the PSCW to increase retail electric and natural gas rates $71.1 million and $19.0 million, respectively, with rates proposed to be effective January 1, 2014. The filing includes a request for a 10.75% return on common equity and a common equity ratio of 51.11% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the purchase and operation of the Fox Energy Center, the completion of a one-time fuel refund to customers in 2013, increased electric transmission costs, additional construction related to the installation of environmental controls and the improvement of electric reliability, the recovery of pension and other employee benefit costs deferred in 2013 rates, and general inflation. Partially offsetting these increases are lower purchased power capacity costs and a refund to customers resulting from WPS's decoupling mechanism. The proposed retail natural gas rate increase is generally the result of the recovery of amounts related to decoupling, increased costs of inspecting natural gas lines for safety, the recovery of pension and other employee benefit costs deferred in 2013 rates, and general inflation.

In August 2013, the PSCW Staff submitted testimony and recommended rate increases of $9.3 million and $7.8 million for retail electric and natural gas, respectively, reflecting a 10.20% return on common equity. Their recommendation also included a common equity ratio of 50.14% in WPS's regulatory capital structure. The PSCW held both technical and public hearings in September 2013. In October 2013, WPS issued an initial brief revising its requested retail electric and natural gas rate increases to approximately $60 million and approximately $14 million, respectively, including a reduced return on common equity of 10.60%. Included in these revised amounts, is WPS's request for recovery of $1.7 million for the Wisconsin retail allocation of environmental remediation capital and operating costs related to WPS's Consent Decree with the EPA. See Note 12, "Commitments and Contingencies," for more information. Finally, WPS requested the removal of the annual caps associated with the decoupling mechanism that is currently in place. WPS's revised request is a result of WPS's current position on contested issues. New rates are expected to be effective January 1, 2014.

2013 Rates

In December 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement included a $28.5 million imputed retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase is being deferred for recovery in a future rate proceeding. As a result, there was no change to customers' 2013 retail electric rates. The settlement agreement also included a $3.4 million retail natural gas rate decrease, which included a deferral of $2.1 million of pension and other employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were reduced based on updated December 31, 2012, pension and other employee benefit cost estimates, which were filed with the PSCW in March 2013. The settlement agreement reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The settlement agreement also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. Lastly, the settlement agreement authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek Wind Project.

A new decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism is based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism does not cover all customer classes, and it continues to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate proceeding.

2012 Rates

In December 2011, the PSCW issued a final written order for WPS, effective January 1, 2012. It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million. The electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% price variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs.

Michigan

2014 MGU Rate Case

In October 2013, MGU entered into a settlement agreement with the MPSC and all other involved parties resolving all issues in the MGU 2014 rate case. The settlement agreement provides for a retail natural gas rate increase of $4.5 million, effective January 1, 2014. The rates reflect a 10.25% return on common equity and a common equity ratio of 48.62% in MGU's regulatory capital structure. Additionally, the order requires MGU to terminate its existing decoupling mechanism, effective December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminates MGU's existing uncollectible expense true-up mechanism after December 31, 2013.

MGU Depreciation Case

In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in the first quarter of 2013. In June 2013, the MPSC issued an order related to MGU's most recent depreciation case. This order also approved a settlement agreement reflecting recovery of these previously disallowed costs.

2014 UPPCO Rate Case

In June 2013, UPPCO filed an application with the MPSC to increase retail electric rates $7.9 million. Interim rates could be effective on January 1, 2014. UPPCO's request reflects a 10.75% return on common equity and a common equity ratio of 54.98% in its regulatory capital structure. The request was primarily driven by capital investments associated with FERC mandated replacements and upgrades of hydroelectric facilities, and increased costs associated with uncollectibles expense, line clearance, system losses, and general inflation. UPPCO is also requesting authority from the MPSC to implement a revenue adjustment mechanism that operates similar to a decoupling mechanism.

2012 UPPCO Rates

In December 2011, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $4.2 million, effective January 1, 2012. The new rates reflect a 10.20% return on common equity and a common equity ratio of 54.90% in its regulatory capital structure. The order stated that if UPPCO filed a rate case in 2013, the earliest effective date for new final rates or self-implemented rates would be January 1, 2014. Additionally, the order required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2013. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. It includes an annual 1.5% cap based on distribution revenues approved in the rate case. UPPCO had no decoupling mechanism in place during 2012.

In April 2012, the State of Michigan Court of Appeals ruled in a Detroit Edison proceeding that the MPSC did not have authority to approve electric decoupling mechanisms. This decision was not appealed. As a result of this ruling, UPPCO expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery. However, in August 2012, the MPSC issued an order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement. Therefore, in the third quarter of 2012, UPPCO reversed the $1.5 million previously expensed in the first quarter of 2012.

Illinois

Qualifying Infrastructure Plant (QIP) Rider

In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives PGL a cost recovery mechanism for Illinois natural gas infrastructure upgrades that will be collected through a surcharge on customer bills. Later in July 2013, the ICC adopted emergency rules to implement the law. The ICC also opened a docket to develop permanent rules, which will replace the emergency rules. This Act eliminates a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation once PGL obtains an infrastructure tariff. In September 2013, PGL filed with the ICC requesting the proposed rider. The ICC must act no later than January 17, 2014. The ICC may modify the rider only to ensure compliance with the law. The rider would take effect on January 1 of the year in which the ICC issues its order.

2013 Rates

In June 2013, the ICC issued a final order authorizing a retail natural gas rate increase of $57.2 million for PGL and $6.6 million for NSG, effective June 27, 2013. The rates for PGL reflect a 9.28% return on common equity and a common equity ratio of 50.43% in its regulatory capital structure. The rates for NSG reflect a 9.28% return on common equity and a common equity ratio of 50.32% in its regulatory capital structure. The rate order also allows PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Appellate Court (Court).

In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG had asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors have requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. If the deferred tax asset created by the 2012 tax NOL is excluded from rate base or the corrections requested by PGL and NSG are not made, there is a potential that the federal income tax "normalization" rules could be violated. These rules specify that the benefit of claiming accelerated depreciation for federal income tax purposes cannot be given to customers before the tax cash flow is received by the company. Once received, the benefit must be given to customers over the useful life of the underlying property. A violation could cause PGL and NSG to lose the ability to claim accelerated depreciation deductions for income tax purposes. We believe this outcome is unlikely.

2012 Rates

In January 2012, the ICC issued a final order authorizing a retail natural gas rate increase of $57.8 million for PGL and $1.9 million for NSG, effective January 21, 2012. The rates for PGL reflected a 9.45% return on common equity and a common equity ratio of 49.00% in PGL's regulatory capital structure. The rates for NSG reflected a 9.45% return on common equity and a common equity ratio of 50.00% in NSG's regulatory capital structure. The rate order also approved a permanent decoupling mechanism.

The Illinois Attorney General and Citizens Utility Board appealed to the Court the ICC's authority to approve PGL's and NSG's decoupling mechanism and filed a motion to stay the implementation of the permanent decoupling mechanism or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanism subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG had established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanism. As a result, the reserves recorded in 2012 were reversed in the first quarter of 2013. PGL's and NSG's permanent decoupling mechanism is in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to appeal the Court's decision. The Illinois Supreme Court granted the request in September 2013. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse Illinois Supreme Court decision. Between April 1, 2013 and December 31, 2013, PGL and NSG expect to recover $14.8 million and $1.7 million, respectively, related to their 2012 decoupling mechanisms. As of September 30, 2013, PGL and NSG have recovered $6.4 million and $0.8 million, respectively, related to the 2012 decoupling mechanisms.

Minnesota

2014 Rate Case

In September 2013, MERC filed an application with the MPUC to increase retail natural gas distribution rates by $14.2 million. Interim rates could be effective on January 1, 2014. MERC's request reflects a 10.75% return on common equity and a common equity ratio of 50.31% in its regulatory capital structure. The request was primarily driven by general inflation, property taxes, improvements to customer service programs, efforts to expand the customer base which would have a positive rate effect in the future, and operating and maintenance projects to ensure reliability and safety for customers.

2011 Rates

In July 2012, the MPUC approved a written order for MERC authorizing a retail natural gas rate increase of $11.0 million, effective January 1, 2013. The new rates reflect a 9.70% return on common equity and a common equity ratio of 50.48% in its regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

Federal

Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they would no longer receive due to this rate elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) be put into place. Load-serving entities paid these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006.

Integrys Energy Services initially expensed the majority of the total $19.2 million of billings paid during the transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC's SECA order and the transmission owners' FERC-ordered compliance filings. Integrys Energy Services protested the FERC’s SECA order, and through various rulings, ultimately received adverse decisions on most substantive issues. Integrys Energy Services appealed the adverse FERC decisions to the U.S. Court of Appeals for the D.C. Circuit.

In January 2013, Integrys Energy Services reached a settlement on all remaining issues with American Electric Power Service Corporation (AEP), the transmission owner affected the most from SECA payments collected from Integrys Energy Services. The parties filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC in January 2013. In July 2013, the FERC issued an order approving the uncontested Settlement Agreement. In September 2013, AEP made a lump sum payment of $9.5 million to Integrys Energy Services in complete settlement of the matters at issue (which included a $3.8 million receivable previously recorded). As a result, Integrys Energy Services recorded $5.7 million in other income, representing the portion of the $9.5 million settlement not previously recognized. In September 2013, Integrys Energy Services withdrew its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit, as discussed above.