Regulatory Matters	6 Months Ended
Jun. 30, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Matters	Regulatory Matters Gas Distribution Operations Regulatory Matters Significant Rate Developments. On June 18, 2013, Northern Indiana, the OUCC and other customer stakeholder groups filed a unanimous agreement with the IURC to extend Northern Indiana's 2010 natural gas customer rate settlement through 2020. A decision on the filing is expected by the end of 2013. On April 15, 2013, Columbia of Ohio filed an application that seeks authority to reduce its Percentage of Income Payment Plan Rider. This revised rate, which will result in an annual reduction of revenues by approximately $6.7 million, became effective May 31, 2013. On April 15, 2013, Columbia of Ohio filed an application to reduce its Uncollectible Expense Rider by $16.5 million. On May 29, 2013, the PUCO issued an Entry that approved the revised Uncollectible Expense Rider. On April 1, 2013, Columbia of Ohio filed an application that seeks authority to recover the $8.2 million base chip transition cost currently deferred. The parties have filed comments and are awaiting a ruling from the PUCO. On December 24, 2012, Columbia of Ohio filed an application for authority to continue its capital expenditure program in 2013 and succeeding years, and for the authority to defer the related post in-service carrying charges, depreciation expense, and property taxes on the assets of the capital expenditure program placed into service in 2013. The corresponding expenditures are expected to total approximately $8.0 million in 2013. Comments have been filed and the parties are awaiting a PUCO ruling. On November 30, 2012, Columbia of Ohio filed a Notice of Intent to file an application to adjust rates associated with its IRP and DSM Riders. Columbia of Ohio filed its Application on February 28, 2013 and indicated that Columbia of Ohio is seeking to increase revenues by approximately $29 million. A stipulation resolving all issues was filed on April 9, 2013, and a hearing was held on April 11, 2013. On April 24, 2013, the PUCO approved the stipulation. On May 29, 2013, Columbia of Kentucky filed an application with the Kentucky PSC requesting an increase of approximately $16.6 million in base rate revenues, the use of a forecasted test period and a revenue normalization adjustment to recognize changes in customer usage not included in Columbia of Kentucky's current weather normalization adjustment. The parties are engaged in discovery, and a hearing will likely be scheduled for the fourth quarter of 2013. If approved, new rates are expected to go into effect January 2014. On September 28, 2012, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $77.3 million annually and providing three options for residential rate design in order to mitigate revenue volatility associated with usage based rates. Columbia of Pennsylvania is the first utility in Pennsylvania to seek Pennsylvania PUC approval to design rates to recover costs that are projected to be incurred after the implementation of those new rates, as recently authorized by the Pennsylvania General Assembly with the passage of Act 11 of 2012. Accordingly, Columbia of Pennsylvania's filing sought to implement rates in July 2013 under which Columbia of Pennsylvania would immediately begin to recover costs that are projected for the twelve-month period ending June 30, 2014. On March 15, 2013, the parties to the rate case filed a joint petition formally seeking Pennsylvania PUC approval of a settlement that features a revenue increase of $55.3 million annually and the implementation of a Weather Normalization Adjustment, whereby residential charges will be adjusted in the event of winter temperatures that deviate from historic norms by plus or minus five percent. The Pennsylvania PUC issued an order approving the settlement on May 23, 2013, and new rates went into effect July 1, 2013. On July 3, 2013, the VSCC issued an order approving an amendment to Columbia of Virginia's infrastructure tracking mechanism pursuant to the Steps to Advance Virginia's Energy (“SAVE”) Plan Act. Columbia of Virginia's five year SAVE Plan provides for recovery of costs associated with the accelerated replacement of certain facilities designed to improve system safety or reliability through a rate rider. The amendment increases authorized annual investments by $5 million from 2013 through 2016, to $25 million per year. In addition, the amendment expands the types of infrastructure eligible for the tracking mechanism and affords Columbia of Virginia additional flexibility with respect to annual and total plan limitations on expenditures. On April 16, 2013, Columbia of Massachusetts submitted a filing with the Massachusetts DPU requesting an annual revenue requirement increase of $30.1 million. An order is expected by February 28, 2014, with new rates going into effect on March 1, 2014. On March 7, 2013, the Massachusetts DPU issued its final order approving $10.5 million of decoupling revenues for Columbia of Massachusetts' Peak Period RDAF that was effective November 1, 2012 through April 30, 2013. On February 27, 2013, Columbia of Maryland filed a base rate case with the Maryland PSC, seeking a revenue increase of approximately $5.3 million annually and seeking to implement a residential Revenue Normalization Adjustment in order to decouple revenues from customer usage and seeking to recover costs for environmental remediation associated with a former manufactured gas plant operated by a Columbia of Maryland predecessor in Hagerstown, Maryland. The Maryland Office of Peoples Counsel has opposed recovery of the cost to acquire and remediate impacted property that is adjacent to the service center. Commission Staff has recommended that Columbia of Maryland recover half of the cost to acquire and remediate the adjacent property. Hearings were held in June 2013, with new rates expected to take effect on September 25, 2013. Cost Recovery and Trackers. A significant portion of the distribution companies' revenue is related to the recovery of gas costs, the review and recovery of which occurs via standard regulatory proceedings. All states require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. NiSource distribution companies have historically been found prudent in the procurement of gas supplies to serve customers. Certain operating costs of the NiSource distribution companies are significant, recurring in nature, and generally outside the control of the distribution companies. Some states allow the recovery of such costs via cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, gas energy efficiency programs, and bad debt recovery mechanisms. Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as bad debt expenses. Increases in the expenses that are the subject of trackers, result in a corresponding increase in net revenues and therefore have essentially no impact on total operating income results. Certain of the NiSource distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction. Columbia Pipeline Group (formerly known as Gas Transmission and Storage) Operations Regulatory Matters Columbia Transmission Customer Settlement. On January 24, 2013, the FERC approved the Columbia Transmission Customer Settlement (the "Settlement"). In March 2013, Columbia Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Transmission expects to invest approximately $1.5 billion over a five-year period to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter. The Settlement also provides for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which begins January 1, 2014, that equates to approximately $25 million in revenues annually thereafter. The Settlement includes a Capital Cost Recovery Mechanism (CCRM), a tracker mechanism that will allow Columbia Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Transmission's long-term plan to modernize its interstate transmission system. The CCRM provides for a 14% revenue requirement with a portion designated as a recovery of increased taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate will be effective on February 1, 2014. The CCRM will give Columbia Transmission the opportunity to recover its revenue requirement associated with $1.5 billion investment in the modernization program, while maintaining competitive rates for its shippers. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Transmission incurs after satisfying the requirement associated with $100.0 million in annual capital maintenance expenditures. The CCRM applies to Columbia Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term. Chesapeake, Virginia LNG Facility Modernization. In connection with long-term extensions of their expiring service agreements, the three customers of Columbia Transmission's Chesapeake, Virginia LNG peaking facility agreed to fund upgrades to modernize the facility. Under the settlement, Columbia Transmission will invest approximately $30 million to upgrade the facility and each customer will extend its contract for 15 years. The settlement was filed with the FERC on February 28, 2013 and approved without modification on June 3, 2013. The project's first phase is scheduled to be complete in the fourth quarter of 2013. Cost Recovery Trackers. A significant portion of the transmission and storage regulated companies' revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under section 7 of the Natural Gas Act. However, certain operating costs of the NiSource regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas. The FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies' rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, environmental, and operational purchase and sales of natural gas. Electric Operations Regulatory Matters Significant Rate Developments. As part of a multi-state effort to strengthen the electric transmission system serving the Midwest, Northern Indiana anticipates making investments in two projects that were authorized by the MISO and are scheduled to be in service during the latter part of the decade. On July 19, 2012 and December 19, 2012, the FERC issued orders approving construction work in progress in rate base and abandoned plant cost recovery requested by Northern Indiana, for the 100-mile, 345 kV transmission project and its right to develop 50 percent of the 66-mile, 765 kV project. On December 19, 2012, the FERC issued an order authorizing Northern Indiana's request to transition to forward looking rates, allowing more timely recovery of Northern Indiana's investment in transmission assets. Northern Indiana began recording revenue in the first quarter of 2013 calculated by the FERC's forward looking rate, based on an average construction work in progress balance of $19.8 million. For the six months ended June 30, 2013 revenue of $1.5 million was recorded. On April 30, 2013, Indiana Governor Pence signed Senate Enrolled Act 560 into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. The cost recovery mechanism is referred to as a Transmission, Distribution and Storage System Improvement Charge or "TDSIC." Provisions of the TDSIC require that, among other things, requests for recovery include a seven year plan of eligible investments. Once the plan is approved by the IURC, 80 percent of eligible costs can be recovered using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, including AFUDC, post in service carrying charges, operation and maintenance expenses, depreciation, and property taxes. The remaining 20 percent of recoverable costs are to be deferred for future recovery in Northern Indiana's next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent in total retail revenues. On July 19, 2013, Northern Indiana filed its electric TDSIC with the IURC. The filing included the seven year plan of eligible investments for a total of approximately $1.1 billion with the majority of the spend occurring in years 2016 through 2020. Cost Recovery and Trackers. A significant portion of Northern Indiana's revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a standard, quarterly, “summary” regulatory proceeding in Indiana. Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of Northern Indiana. The IURC allows for recovery of such costs via cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for Northern Indiana to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, and environmental related costs. Northern Indiana has approval from the IURC to recover certain environmental related costs through an ECT. Under the ECT, Northern Indiana is permitted to recover (1) AFUDC and a return on the capital investment expended by Northern Indiana to implement environmental compliance plan projects through an ECRM and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational through an EERM. On April 24, 2013, the IURC issued an order on ECR-21 approving Northern Indiana's request to begin earning a return on net capital expenditures of $376.4 million.

Regulatory Matters

Gas Distribution Operations Regulatory Matters

Significant Rate Developments. On June 18, 2013, Northern Indiana, the OUCC and other customer stakeholder groups filed a unanimous agreement with the IURC to extend Northern Indiana's 2010 natural gas customer rate settlement through 2020. A decision on the filing is expected by the end of 2013.

On April 15, 2013, Columbia of Ohio filed an application that seeks authority to reduce its Percentage of Income Payment Plan Rider. This revised rate, which will result in an annual reduction of revenues by approximately $6.7 million, became effective May 31, 2013.

On April 15, 2013, Columbia of Ohio filed an application to reduce its Uncollectible Expense Rider by $16.5 million. On May 29, 2013, the PUCO issued an Entry that approved the revised Uncollectible Expense Rider.

On April 1, 2013, Columbia of Ohio filed an application that seeks authority to recover the $8.2 million base chip transition cost currently deferred. The parties have filed comments and are awaiting a ruling from the PUCO.

On December 24, 2012, Columbia of Ohio filed an application for authority to continue its capital expenditure program in 2013 and succeeding years, and for the authority to defer the related post in-service carrying charges, depreciation expense, and property taxes on the assets of the capital expenditure program placed into service in 2013. The corresponding expenditures are expected to total approximately $8.0 million in 2013. Comments have been filed and the parties are awaiting a PUCO ruling.

On November 30, 2012, Columbia of Ohio filed a Notice of Intent to file an application to adjust rates associated with its IRP and DSM Riders. Columbia of Ohio filed its Application on February 28, 2013 and indicated that Columbia of Ohio is seeking to increase revenues by approximately $29 million. A stipulation resolving all issues was filed on April 9, 2013, and a hearing was held on April 11, 2013. On April 24, 2013, the PUCO approved the stipulation.

On May 29, 2013, Columbia of Kentucky filed an application with the Kentucky PSC requesting an increase of approximately $16.6 million in base rate revenues, the use of a forecasted test period and a revenue normalization adjustment to recognize changes in customer usage not included in Columbia of Kentucky's current weather normalization adjustment. The parties are engaged in discovery, and a hearing will likely be scheduled for the fourth quarter of 2013. If approved, new rates are expected to go into effect January 2014.

On September 28, 2012, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $77.3 million annually and providing three options for residential rate design in order to mitigate revenue volatility associated with usage based rates. Columbia of Pennsylvania is the first utility in Pennsylvania to seek Pennsylvania PUC approval to design rates to recover costs that are projected to be incurred after the implementation of those new rates, as recently authorized by the Pennsylvania General Assembly with the passage of Act 11 of 2012. Accordingly, Columbia of Pennsylvania's filing sought to implement rates in July 2013 under which Columbia of Pennsylvania would immediately begin to recover costs that are projected for the twelve-month period ending June 30, 2014. On March 15, 2013, the parties to the rate case filed a joint petition formally seeking Pennsylvania PUC approval of a settlement that features a revenue increase of $55.3 million annually and the implementation of a Weather Normalization Adjustment, whereby residential charges will be adjusted in the event of winter temperatures that deviate from historic norms by plus or minus five percent. The Pennsylvania PUC issued an order approving the settlement on May 23, 2013, and new rates went into effect July 1, 2013.

On July 3, 2013, the VSCC issued an order approving an amendment to Columbia of Virginia's infrastructure tracking mechanism pursuant to the Steps to Advance Virginia's Energy (“SAVE”) Plan Act. Columbia of Virginia's five year SAVE Plan provides for recovery of costs associated with the accelerated replacement of certain facilities designed to improve system safety or reliability through a rate rider. The amendment increases authorized annual investments by $5 million from 2013 through 2016, to $25 million per year. In addition, the amendment expands the types of infrastructure eligible for the tracking mechanism and affords Columbia of Virginia additional flexibility with respect to annual and total plan limitations on expenditures.

On April 16, 2013, Columbia of Massachusetts submitted a filing with the Massachusetts DPU requesting an annual revenue requirement increase of $30.1 million. An order is expected by February 28, 2014, with new rates going into effect on March 1, 2014.

On March 7, 2013, the Massachusetts DPU issued its final order approving $10.5 million of decoupling revenues for Columbia of Massachusetts' Peak Period RDAF that was effective November 1, 2012 through April 30, 2013.

On February 27, 2013, Columbia of Maryland filed a base rate case with the Maryland PSC, seeking a revenue increase of approximately $5.3 million annually and seeking to implement a residential Revenue Normalization Adjustment in order to decouple revenues from customer usage and seeking to recover costs for environmental remediation associated with a former manufactured gas plant operated by a Columbia of Maryland predecessor in Hagerstown, Maryland. The Maryland Office of Peoples Counsel has opposed recovery of the cost to acquire and remediate impacted property that is adjacent to the service center. Commission Staff has recommended that Columbia of Maryland recover half of the cost to acquire and remediate the adjacent property. Hearings were held in June 2013, with new rates expected to take effect on September 25, 2013.

Cost Recovery and Trackers. A significant portion of the distribution companies' revenue is related to the recovery of gas costs, the review and recovery of which occurs via standard regulatory proceedings. All states require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. NiSource distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.

Certain operating costs of the NiSource distribution companies are significant, recurring in nature, and generally outside the control of the distribution companies. Some states allow the recovery of such costs via cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, gas energy efficiency programs, and bad debt recovery mechanisms.

Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as bad debt expenses. Increases in the expenses that are the subject of trackers, result in a corresponding increase in net revenues and therefore have essentially no impact on total operating income results.

Certain of the NiSource distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.

Columbia Pipeline Group (formerly known as Gas Transmission and Storage) Operations Regulatory Matters

Columbia Transmission Customer Settlement. On January 24, 2013, the FERC approved the Columbia Transmission Customer Settlement (the "Settlement"). In March 2013, Columbia Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Transmission expects to invest approximately $1.5 billion over a five-year period to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter.

The Settlement also provides for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which begins January 1, 2014, that equates to approximately $25 million in revenues annually thereafter.

The Settlement includes a Capital Cost Recovery Mechanism (CCRM), a tracker mechanism that will allow Columbia Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Transmission's long-term plan to modernize its interstate transmission system. The CCRM provides for a 14% revenue requirement with a portion designated as a recovery of increased taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate will be effective on February 1, 2014. The CCRM will give Columbia Transmission the opportunity to recover its revenue requirement associated with $1.5 billion investment in the modernization program, while maintaining competitive rates for its shippers. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Transmission incurs after satisfying the requirement associated with $100.0 million in annual capital maintenance expenditures. The CCRM applies to Columbia Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term.

Chesapeake, Virginia LNG Facility Modernization. In connection with long-term extensions of their expiring service agreements, the three customers of Columbia Transmission's Chesapeake, Virginia LNG peaking facility agreed to fund upgrades to modernize the facility. Under the settlement, Columbia Transmission will invest approximately $30 million to upgrade the facility and each customer will extend its contract for 15 years. The settlement was filed with the FERC on February 28, 2013 and approved without modification on June 3, 2013. The project's first phase is scheduled to be complete in the fourth quarter of 2013.

Cost Recovery Trackers. A significant portion of the transmission and storage regulated companies' revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under section 7 of the Natural Gas Act. However, certain operating costs of the NiSource regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas. The FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies' rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, environmental, and operational purchase and sales of natural gas.

Electric Operations Regulatory Matters

Significant Rate Developments. As part of a multi-state effort to strengthen the electric transmission system serving the Midwest, Northern Indiana anticipates making investments in two projects that were authorized by the MISO and are scheduled to be in service during the latter part of the decade. On July 19, 2012 and December 19, 2012, the FERC issued orders approving construction work in progress in rate base and abandoned plant cost recovery requested by Northern Indiana, for the 100-mile, 345 kV transmission project and its right to develop 50 percent of the 66-mile, 765 kV project. On December 19, 2012, the FERC issued an order authorizing Northern Indiana's request to transition to forward looking rates, allowing more timely recovery of Northern Indiana's investment in transmission assets. Northern Indiana began recording revenue in the first quarter of 2013 calculated by the FERC's forward looking rate, based on an average construction work in progress balance of $19.8 million. For the six months ended June 30, 2013 revenue of $1.5 million was recorded.

On April 30, 2013, Indiana Governor Pence signed Senate Enrolled Act 560 into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. The cost recovery mechanism is referred to as a Transmission, Distribution and Storage System Improvement Charge or "TDSIC." Provisions of the TDSIC require that, among other things, requests for recovery include a seven year plan of eligible investments. Once the plan is approved by the IURC, 80 percent of eligible costs can be recovered using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, including AFUDC, post in service carrying charges, operation and maintenance expenses, depreciation, and property taxes. The remaining 20 percent of recoverable costs are to be deferred for future recovery in Northern Indiana's next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent in total retail revenues. On July 19, 2013, Northern Indiana filed its electric TDSIC with the IURC. The filing included the seven year plan of eligible investments for a total of approximately $1.1 billion with the majority of the spend occurring in years 2016 through 2020.

Cost Recovery and Trackers. A significant portion of Northern Indiana's revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a standard, quarterly, “summary” regulatory proceeding in Indiana.

Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of Northern Indiana. The IURC allows for recovery of such costs via cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for Northern Indiana to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, and environmental related costs.

Northern Indiana has approval from the IURC to recover certain environmental related costs through an ECT. Under the ECT, Northern Indiana is permitted to recover (1) AFUDC and a return on the capital investment expended by Northern Indiana to implement environmental compliance plan projects through an ECRM and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational through an EERM.

On April 24, 2013, the IURC issued an order on ECR-21 approving Northern Indiana's request to begin earning a return on net capital expenditures of $376.4 million.