REGULATORY ENVIRONMENT	3 Months Ended
Mar. 31, 2013
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT	NOTE 21 — REGULATORY ENVIRONMENT Wisconsin 2014 Rates On March 29, 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, and additional construction related to the installation of environmental controls and the improvement of electric reliability. 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, and general inflation. 2013 Rates On December 6, 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement includes 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 is no change to customers' 2013 retail electric rates. The settlement agreement also includes a $3.4 million retail natural gas rate decrease, which includes a deferral of $2.4 million of employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were subject to downward adjustment based on updated December 31, 2012, pension and benefit cost estimates, which were filed with the PSCW on March 1, 2013. The settlement agreement reflects 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 began being recovered from customers 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 also 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 On December 9, 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 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 2013. MGU has modified its depreciation study currently pending before the MPSC to reflect recovery of these previously disallowed costs. The deadline to appeal the Michigan Court of Appeals' order was March 7, 2013. 2012 UPPCO Rates On December 20, 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 UPPCO's regulatory capital structure. The order states that if UPPCO files a rate case in 2013, the earliest effective date for new final rates or self-implemented rates is 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 2013 Rate Cases On July 31, 2012, PGL and NSG filed applications with the ICC to increase retail natural gas rates $78.3 million and $9.8 million, respectively, with rates expected to be effective in July 2013. Both PGL's and NSG's requests reflect a 10.75% return on common equity and a target common equity ratio of 50.00% in their regulatory capital structures. In their briefs, PGL and NSG reflected revised increases of $97.0 million and $9.6 million, respectively, including a revised requested return on common equity of 10.00%. The revised request at PGL was primarily driven by increased costs due to new permitting and restoration requirements, as well as modifications in natural gas main and service pipe installation procedures. In its reply brief, the ICC Staff recommended rate increases of $12.9 million and $3.4 million for PGL and NSG, respectively, as well as a 9.06% return on common equity for both companies. Their recommendation also included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively. In the Illinois Attorney General's reply brief, it recommended rate increases not to exceed $15.4 million- and $2.6 million for PGL and NSG, respectively, and in its initial brief, adopted the Staff's return on equity recommendations. On April 26, 2013, the Administrative Law Judges served their proposed order recommending rate increases of $52.0 million and $6.1 million for PGL and NSG, respectively. This reflects a 9.33% return on common equity for both companies. The proposed order included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively. Exception briefs and replies to the proposed order are due May 9, 2013 and May 16, 2013, respectively. The ICC will issue a final order in this proceeding no later than June 27, 2013. 2012 Rates On January 10, 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 appealed to the Illinois Appellate Court (Court) the ICC's authority to approve decoupling 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. Therefore, PGL's and NSG's permanent decoupling mechanism is in place for 2013, and decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse decision on appeal at the Illinois Supreme Court. 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. Minnesota 2011 Rates On July 13, 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 MERC's 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 received 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 in August 2006, the Administrative Law Judge hearing the case issued an Initial Decision that was in substantial agreement with all of Integrys Energy Services' positions. In May 2010, the FERC ruled favorably for Integrys Energy Services on two issues, but reversed the rulings of the Initial Decision on nearly every other substantive issue. Integrys Energy Services and numerous other parties filed for rehearing of the FERC's order on the Initial Decision, which the FERC denied on September 30, 2011. The FERC has yet to issue an order on the compliance filings made by the transmission owners. Integrys Energy Services has appealed the adverse FERC decision to the U.S. Court of Appeals for the D.C. Circuit. As a result of the rulings received from the FERC in May 2010, Integrys Energy Services had a $3.8 million receivable recorded at March 31, 2013. In January 2013, Integrys Energy Services reached a settlement with American Electric Power Service Corporation (AEP), and filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC on January 10, 2013. If approved by the FERC, the Settlement Agreement will become effective on the date the FERC's order approving the Settlement Agreement becomes final and nonappealable. The Settlement Agreement provides that AEP would remit to Integrys Energy Services, in complete settlement of the matters at issue, a lump sum payment of $9.5 million within five business days of the effective date of the Settlement Agreement, and within five days of receipt of the lump sum payment, Integrys Energy Services would withdraw its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit.

NOTE 21 — REGULATORY ENVIRONMENT

Wisconsin

2014 Rates

On March 29, 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, and additional construction related to the installation of environmental controls and the improvement of electric reliability. 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, and general inflation.

2013 Rates

On December 6, 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement includes 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 is no change to customers' 2013 retail electric rates. The settlement agreement also includes a $3.4 million retail natural gas rate decrease, which includes a deferral of $2.4 million of employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were subject to downward adjustment based on updated December 31, 2012, pension and benefit cost estimates, which were filed with the PSCW on March 1, 2013. The settlement agreement reflects 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 began being recovered from customers 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 also 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

On December 9, 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

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 2013. MGU has modified its depreciation study currently pending before the MPSC to reflect recovery of these previously disallowed costs. The deadline to appeal the Michigan Court of Appeals' order was March 7, 2013.

2012 UPPCO Rates

On December 20, 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 UPPCO's regulatory capital structure. The order states that if UPPCO files a rate case in 2013, the earliest effective date for new final rates or self-implemented rates is 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

2013 Rate Cases

On July 31, 2012, PGL and NSG filed applications with the ICC to increase retail natural gas rates $78.3 million and $9.8 million, respectively, with rates expected to be effective in July 2013. Both PGL's and NSG's requests reflect a 10.75% return on common equity and a target common equity ratio of 50.00% in their regulatory capital structures. In their briefs, PGL and NSG reflected revised increases of $97.0 million and $9.6 million, respectively, including a revised requested return on common equity of 10.00%. The revised request at PGL was primarily driven by increased costs due to new permitting and restoration requirements, as well as modifications in natural gas main and service pipe installation procedures.

In its reply brief, the ICC Staff recommended rate increases of $12.9 million and $3.4 million for PGL and NSG, respectively, as well as a 9.06% return on common equity for both companies. Their recommendation also included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively. In the Illinois Attorney General's reply brief, it recommended rate increases not to exceed $15.4 million- and $2.6 million for PGL and NSG, respectively, and in its initial brief, adopted the Staff's return on equity recommendations.

On April 26, 2013, the Administrative Law Judges served their proposed order recommending rate increases of $52.0 million and $6.1 million for PGL and NSG, respectively. This reflects a 9.33% return on common equity for both companies. The proposed order included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively. Exception briefs and replies to the proposed order are due May 9, 2013 and May 16, 2013, respectively. The ICC will issue a final order in this proceeding no later than June 27, 2013.

2012 Rates

On January 10, 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 appealed to the Illinois Appellate Court (Court) the ICC's authority to approve decoupling 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. Therefore, PGL's and NSG's permanent decoupling mechanism is in place for 2013, and decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse decision on appeal at the Illinois Supreme Court. 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.

Minnesota

2011 Rates

On July 13, 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 MERC's 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 received 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 in August 2006, the Administrative Law Judge hearing the case issued an Initial Decision that was in substantial agreement with all of Integrys Energy Services' positions. In May 2010, the FERC ruled favorably for Integrys Energy Services on two issues, but reversed the rulings of the Initial Decision on nearly every other substantive issue. Integrys Energy Services and numerous other parties filed for rehearing of the FERC's order on the Initial Decision, which the FERC denied on September 30, 2011. The FERC has yet to issue an order on the compliance filings made by the transmission owners. Integrys Energy Services has appealed the adverse FERC decision to the U.S. Court of Appeals for the D.C. Circuit. As a result of the rulings received from the FERC in May 2010, Integrys Energy Services had a $3.8 million receivable recorded at March 31, 2013.

In January 2013, Integrys Energy Services reached a settlement with American Electric Power Service Corporation (AEP), and filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC on January 10, 2013. If approved by the FERC, the Settlement Agreement will become effective on the date the FERC's order approving the Settlement Agreement becomes final and nonappealable. The Settlement Agreement provides that AEP would remit to Integrys Energy Services, in complete settlement of the matters at issue, a lump sum payment of $9.5 million within five business days of the effective date of the Settlement Agreement, and within five days of receipt of the lump sum payment, Integrys Energy Services would withdraw its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit.