Regulatory Matters

Regulatory Assets and Liabilities

NiSource follows the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income or expense are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in service rates and recovered from or refunded to customers.

Regulatory assets were comprised of the following items:



At December 31, (in millions)	2013			2012
Assets
Reacquisition premium on debt	$	6.5		$	8.6
R. M. Schahfer Unit 17 and Unit 18 carrying charges and deferred depreciation (see Note 1-H)	2.3			5.5
Unrecognized pension benefit and other postretirement benefit costs (see Note 12)	842.2			1,345.7
Other postretirement costs	67.7			66.3
Environmental costs (see Note 20-D)	68.7			77.5
Regulatory effects of accounting for income taxes (see Note 1-V)	266.8			245.7
Underrecovered gas and fuel costs (see Note 1-P and 1-Q)	46.4			45.0
Depreciation (see Note 1-H)	113.6			113.9
Uncollectible accounts receivable deferred for future recovery	10.5			6.1
Asset retirement obligations (see Note 7)	10.5			16.1
Losses on derivatives (see Note 9)	2.0			17.1
Post-in-service carrying charges	73.1			61.2
EERM operation and maintenance and depreciation deferral	5.9			9.8
MISO (see Note 8)	19.2			28.8
Sugar Creek carrying charges and deferred depreciation (see Note 1-H)	56.8			71.2
Other	119.2			113.7
Total Assets	$	1,711.4		$	2,232.2
Less amounts included as Underrecovered gas and fuel cost	(46.4		)	(45.0		)
Total Regulatory Assets reflected in Current Regulatory Assets and Other Regulatory Assets	$	1,665.0		$	2,187.2

Regulatory liabilities were comprised of the following items:



At December 31, (in millions)	2013			2012
Liabilities
Overrecovered gas and fuel costs (see Notes 1-P and 1-Q)	$	32.2		$	22.1
Cost of removal (see Note 7)	1,435.2			1,437.5
Regulatory effects of accounting for income taxes (see Note 1-V)	60.4			76.9
Unrecognized pension benefit and other postretirement benefit costs (see Note 12)	49.4			0.4
Other postretirement costs	111.9			97.4
Percentage of income plan	—			16.0
Off-system sales margin sharing	3.7			5.8
Other	69.4			130.9
Total Liabilities	$	1,762.2		$	1,787.0
Less amounts included as Overrecovered gas and fuel cost	(32.2		)	(22.1		)
Total Regulatory Liabilities reflected in Current Regulatory Liabilities and Other Regulatory Liabilities and Other Removal Costs	$	1,730.0		$	1,764.9

Regulatory assets, including underrecovered gas and fuel cost, of approximately $985.9 million as of December 31, 2013 are not earning a return on investment. Regulatory assets of approximately $1,560.7 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. These costs are recovered over a remaining life of up to 41 years. Regulatory assets of approximately $150.7 million at December 31, 2013, require specific rate action.

As noted below, regulatory assets for which costs have been incurred or accrued are included (or expected to be included, for costs incurred subsequent to the most recently approved rate case) in certain companies’ rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

Assets:

Reacquisition premium on debt – The unamortized premiums for debt redeemed by NIPSCO are deferred, amortized and recovered over the term of the replacement issue.

R.M. Schahfer Unit 17 and Unit 18 carrying charges and deferred depreciation – NIPSCO obtained approval from the IURC to capitalize the debt-based carrying charges and deferred depreciation for Schahfer Unit 17 and Unit 18 due to regulatory lag and to amortize such costs over the remaining service life of each unit.

Unrecognized pension benefit and other postretirement benefit costs – In 2007, NiSource adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.

Other postretirement costs – Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms.

Environmental costs – Includes certain recoverable costs of investigating, testing, remediating and other costs related to gas plant sites, disposal sites or other sites onto which material may have migrated. Certain companies defer the costs as a regulatory asset in accordance with regulatory orders, to be recovered in future base rates, billing riders or tracking mechanisms.

Regulatory effects of accounting for income taxes – Represents the deferral and under collection of deferred taxes in the rate making process. In prior years, NiSource has lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as NiSource recovers deferred taxes in the rate making process.

Underrecovered gas and fuel costs – Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue, and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.

Depreciation – Primarily relates to the difference between the depreciation expense recorded by Columbia of Ohio due to a regulatory order and the depreciation expense recorded in accordance with GAAP. The regulatory asset is currently being amortized over the life of the assets. Also included is depreciation associated with the Columbia of Ohio IRP program and Capital Expenditure program. Recovery of these costs is achieved through base rates and rider mechanisms. Refer to Note 1-H for more information.

Uncollectible accounts receivable deferred for future recovery – Represents the difference between certain uncollectible expenses and the recovery of such costs to be collected through cost tracking mechanisms per regulatory orders.

Asset retirement obligations – Represents the timing difference between expense recognition for future obligations and current recovery in rates.

Losses on derivatives – Certain companies are permitted by regulatory orders to participate in commodity price programs to protect customers against the volatility of commodity prices. Unrealized and realized gains or losses related to NiSource’s commodity price risk programs may be deferred per specific orders and the recovery of changes in fair value is dependent upon the individual specific company’s cost recovery or sharing mechanisms in place. Amounts for derivative gains and losses will continue to be deferred as long as the programs are in existence.

Post-in-service carrying charges – Columbia of Ohio has approval from the PUCO by regulatory order to defer debt-based post-in-service carrying charges as a regulatory asset for future recovery. As such, Columbia of Ohio capitalizes a carrying charge on eligible property, plant and equipment from the time it is placed into utility service until recovery of the property, plant and equipment is included in customer rates in base rates or through a rider mechanism. Inclusion in customer rates generally occurs when Columbia of Ohio files its next rate proceeding following the in-service date of the property, plant and equipment.

EERM operation and maintenance and depreciation deferral – NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. Recovery of these costs will continue until such assets are included in rate base through an electric base rate case. The EERM deferred charges represent expenses that will be recovered from customers through an annual EERM Cost Tracker which authorizes the collection of deferred balances over a twelve month period.

MISO – As part of NIPSCO’s participation in the MISO transmission service, wholesale energy and ancillary service markets, certain administrative fees and non-fuel costs have been deferred. The IURC authorized the deferral of certain non-fuel related costs until new electric rates were implemented on December 27, 2011. The deferred balances are being amortized over four years commencing January 2012.

Sugar Creek carrying charges and deferred depreciation – The IURC approved the deferral of debt-based carrying charges and the deferral of depreciation expense for the Sugar Creek assets. NIPSCO continued to defer such amounts until new electric rates were approved and implemented on December 27, 2011. Balances are being amortized over five years beginning January 2012. As of December 31, 2013, the remaining unamortized balance is $42.9 million. An additional $13.9 million is deferred for consideration in NIPSCO's next electric rate case. Management believes this amount is probable of recovery through future rates.

Liabilities:

Overrecovered gas and fuel costs – Represents the difference between the costs of gas and fuel and the recovery of such costs in revenues, and is the basis to adjust future billings for such recoveries on a basis consistent with applicable state-approved tariff provisions. Refunding of these revenues is achieved through tracking mechanisms.

Cost of removal – Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the rate-regulated subsidiaries for future costs to be incurred.

Regulatory effects of accounting for income taxes – Represents amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates and liabilities associated with accelerated tax deductions owed to customers that are established during the rate making process.

Unrecognized pension benefit and other postretirement benefit costs – In 2007, NiSource adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory liability in accordance with regulatory orders or as a result of regulatory precedent, to be refunded through base rates.

Other postretirement costs – Primarily represents cash contributions in excess of postretirement benefit expense that is deferred as a regulatory liability by certain subsidiaries in accordance with regulatory orders.

Percentage of income plan – Represents the difference between costs incurred under a customer assistance program by Columbia of Ohio for targeted low income customers and the recovery of such costs through cost tracking mechanisms per regulatory orders. For 2012, Columbia of Ohio was in an overcollected position for this program, which resulted in a regulatory liability that was refunded to customers.

Off-system sales margin sharing – Revenue generated from off-system sales and capacity release programs are subject to incentive sharing mechanism in which NiSource shares a defined percentage of its margins with customers. Refunding of these revenues is achieved through rate refund mechanisms.

Gas Distribution Operations Regulatory Matters

Significant Rate Developments. 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 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 the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On October 3, 2013, NIPSCO filed its gas TDSIC seven year plan of eligible investments for a total of approximately $710 million with the IURC. An order is expected by the second quarter of 2014.

On June 18, 2013, NIPSCO, the OUCC and other customer stakeholder groups filed a unanimous agreement with the IURC to extend NIPSCO's 2010 natural gas customer rate settlement through 2020. The Settlement Agreement was approved by order issued on August 28, 2013 with the requirement that, on or before November 2020, NIPSCO must file a general rate case.

On December 28, 2011, the IURC issued an Order approving NIPSCO's proposed gas energy efficiency programs and budgets, including a conservation program and recovery of all start-up and deferred cost. A three year budget of $42.4 million was approved.

On November 25, 2013, 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 will file its Application by February 28, 2014. Columbia of Ohio will be seeking to increase revenues by approximately $30.5 million.

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 October 4, 2012, Columbia of Ohio filed a motion requesting an extension of its gas supply auction program, a continuation of its off-system sales and capacity release revenue sharing mechanism, and approval of its pipeline capacity contracts. On November 27, 2012, a non-unanimous stipulation resolving all issues was filed. After hearing, the PUCO issued an Order on January 9, 2013 that approved the stipulation. On May 1, 2013, the Ohio Partners for Affordable Energy appealed the PUCO Order to the Supreme Court of Ohio. The case has been briefed at the Supreme Court of Ohio, and the parties are awaiting the scheduling of oral argument.

On December 9, 2011, Columbia of Ohio filed a Notice of Intent to file an application to extend its IRP. Columbia of Ohio filed an amended Notice of Intent and an amended Motion for Waiver on March 5, 2012. On May 8, 2012, Columbia of Ohio filed its application, supporting exhibits and testimony. On September 26, 2012, the parties filed a Joint Stipulation and Recommendation that provided for the extension of Columbia of Ohio's IRP process for an additional five years and settlement of all issues. On November 28, 2012, the PUCO issued an Opinion and Order in which it 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. A stipulation, signed by all parties and resolving all issues, was filed on November 5, 2013. On December 13, 2013, the Kentucky PSC issued an order approving the stipulation providing for, among other terms, an increase of $7.7 million in revenues using a forecasted test year, a recovery of Columbia of Kentucky’s investment in its pipeline replacement program on a forecasted basis, and continuation of Columbia of Kentucky's CHOICE program for three years. New rates were effective December 29, 2013.

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 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 featuring a revenue increase of $55.3 million annually and the implementation of a Weather Normalization Adjustment, whereby residential charges are 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 $5.0 million from 2013 through 2016, to $25.0 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 September 3, 2013, Columbia of Massachusetts and the Massachusetts Office of the Attorney General filed a Joint Motion for Approval of a Settlement Agreement with the Massachusetts DPU which resolves issues related to the disposition of revenues realized by Columbia of Massachusetts in 2005 from MASSPOWER's buy-out of a special contract with Columbia of Massachusetts, and which were at that time pending before the Massachusetts DPU in D.P.U. 10-10. The Settlement Agreement proposed to return $8.9 million to the customers of Columbia of Massachusetts in the form of a Distribution Rate Credit on their bills during the period November 1, 2013 through April 30, 2014. On October 16, 2013, the DPU issued an order approving the Settlement Agreement.

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. Pursuant to the procedural schedule for this case, on September 3, 2013, Columbia of Massachusetts filed its updated revenue requirement of $29.5 million and on October 16, 2013, filed an updated cost of service for $30 million. Evidentiary hearings and the briefing schedule for the case have concluded. In compliance with the procedural schedule, a final revenue requirements update of $29.9 million was filed on December 16, 2013.

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

On April 13, 2012, Columbia of Massachusetts submitted a filing with the Massachusetts DPU requesting an annual revenue requirement increase of $29.2 million which was subsequently adjusted to $27.4 million. Columbia of Massachusetts filed using a historic test year ended December 31, 2011. Additionally, Columbia of Massachusetts proposed “rate-year, rate base” treatment for recovery of defined capital expenditures beyond the end of the historic test year, as well as expansion of eligible facilities to be recovered through modification to the TIRF. The Massachusetts DPU issued an order on November 1, 2012 approving an annual revenue increase of $7.8 million, effective November 1, 2012, rejecting the rate-year, rate-base proposal, but approving the expansion of eligible facilities to be recovered through the TIRF.

On August 2, 2013, Columbia of Massachusetts filed its 2013-2014 Peak Period LDAF and on September 16, 2013, Columbia of Massachusetts filed its 2013 Pension Expense Factor and its 2013 Residential Assistance Adjustment Factor, each with a proposed effective date of November 1, 2013. The 2013-2014 Peak Period LDAF of $59.0 million was approved on October 30, 2013, for effect November 1, 2013. The 2013 Pension Expense Factor and 2013 Residential Assistance Adjustment Factor, components of the LDAF, were approved subject to further investigation and reconciliation.

On August 2, 2012, Columbia of Massachusetts filed its 2012-2013 Peak Period LDAF and on September 14, 2012, Columbia of Massachusetts filed its 2012 Pension Expense Factor and 2012 Residential Assistance Adjustment Factor, each with a proposed effective date of November 1, 2012. The 2012-2013 Peak Period LDAF of $33.0 million effective November 1, 2012 was approved on October 31, 2012. The 2012 Pension Expense Factor and 2012 Residential Assistance Adjustment Factor components of the LDAF were approved subject to further investigation and reconciliation.

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, where a Columbia of Maryland service center is currently located. Hearings were held in June 2013. On September 23, 2013, the Maryland PSC issued an order that approved an annual revenue increase of $3.6 million, as well as Columbia of Maryland's proposed revenue normalization adjustment. The Maryland PSC permitted recovery of environmental remediation costs for the service center property, but denied recovery of the costs to acquire and remediate the adjacent property. On October 23, 2013, Columbia of Maryland filed a Petition for Judicial Review of the denial of the costs to acquire and remediate the adjacent property. New rates went into 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, 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 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 provided 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 began January 1, 2014, which equates to approximately $25 million in revenues annually thereafter.

The Settlement includes a 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 was 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 million in annual capital maintenance expenditures. The CCRM applies to Columbia Transmission's transportation shippers. The CCRM will not exceed $300 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. On December 31, 2013, Columbia Transmission made its first annual CCRM filing, with billing rates effective February 1, 2014. Through this filing, Columbia Transmission will begin collecting its revenue requirements for the $299.2 million spent on eligible modernization facilities in 2013. For the first CCRM period, these revenue requirements will total approximately $38.9 million. On January 30, 2014, the FERC approved Columbia Transmission's first year CCRM filing.

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 $30.0 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 was completed in the fourth quarter of 2013. The remainder of the project is expected to be completed by mid-2015.

Columbia Gulf Rate Case. On October 28, 2010, Columbia Gulf filed a rate case with the FERC, proposing a rate increase and tariff changes. Among other things, the filing proposed a revenue increase of approximately $50 million to cover increases in the cost of services, which includes adjustments for operation and maintenance expenses, capital investments, adjustments to depreciation rates and expense, rate of return, and increased federal, state and local taxes. On November 30, 2010, the FERC issued an Order allowing new rates to become effective by May 2011, subject to refund. Columbia Gulf placed new rates into effect, subject to refund, on May 1, 2011. Columbia Gulf and the active parties to the case negotiated a settlement, which was filed with the FERC on September 9, 2011. On September 30, 2011, the Chief Judge severed the issues relating to a contesting party for separate hearing and decision. On October 4, 2011, the Presiding Administrative Law Judge certified the settlement agreement as uncontested to the FERC with severance of the contesting party from the settlement. On November 1, 2011, Columbia Gulf began billing interim rates to customers. On December 1, 2011, the FERC issued an order approving the settlement without change. The key elements of the settlement, which was a “black box agreement”, include: (1) increased base rate to $0.1520 per Dth and (2) establishing a postage stamp rate design. No protests to the order were filed and therefore, pursuant to the Settlement, the order became final on January 1, 2012 which made the settlement effective on February 1, 2012. On February 2, 2012, the Presiding Administrative Law Judge issued an initial decision granting a joint motion terminating the remaining litigation with the contesting party and allowing it to become a settling party. The FERC issued an order on March 15, 2012, affirming the initial decision, which terminated the remaining litigation with the contesting party. Refunds of approximately $16.0 million, accrued as of December 31, 2011, were disbursed to settling parties in March 2012.

Cost Recovery Trackers and other similar mechanisms. 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, operational purchases and sales of natural gas, and the revenue requirement for capital investments made under Columbia Transmission's long-term plan to modernize its interstate transmission system as discussed above.

Electric Operations Regulatory Matters

Significant Rate Developments. As part of a multi-state effort to strengthen the electric transmission system serving the Midwest, NIPSCO 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 NIPSCO 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 NIPSCO's request to transition to forward looking rates, allowing more timely recovery of NIPSCO's investment in transmission assets. On August 22, 2012, the IURC issued an order authorizing NIPSCO to retain certain revenues under MISO Schedule 26-A. NIPSCO began recording revenue in the first quarter of 2013 using a forward looking rate, based on an average construction work in progress balance of $19.8 million. For the twelve months ended December 31, 2013 revenue of $2.4 million was recorded.

On July 19, 2013, NIPSCO filed its electric TDSIC, further discussed above, 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. On February 17, 2014, the IURC issued an order approving NIPSCO’s seven year plan of eligible investments. The Order also granted NIPSCO ratemaking relief associated with the eligible investments through a rate adjustment mechanism, described above. NIPSCO anticipates filing its first semi-annual tracker petition in the third quarter of 2014.

On December 18, 2013, the IURC issued an Order approving NIPSCO's proposed electric energy efficiency programs and budgets through December 31, 2014, including authorization to use its energy efficiency recovery mechanism to recover costs and lost margins for 2014.

On November 12, 2013, several industrial customers, including INDIEC, filed a complaint at the FERC regarding the 12.38% base ROE used to set the MISO Transmission Owners' transmission rates and requesting a reduction in the base ROE to 9.15%. The complaint further requests that FERC limit the capital structure of MISO Transmission Owners to no more than 50% common equity for ratemaking purposes and that FERC eliminate incentive adders for membership in a RTO. NIPSCO joined in an answer defending the 12.38% base ROE and motion to dismiss the complaint filed on behalf of a group of MISO Transmission Owners on January 6, 2014. NIPSCO is unable to estimate the impact of this complaint or the timing of any potential impact at this time.

On July 18, 2011, NIPSCO filed with the IURC a settlement in its 2010 Electric Rate Case with the OUCC, Northern Indiana Industrial Group, NLMK Indiana and Indiana Municipal Utilities Group. The settlement agreement limited the proposed base rate impact to the residential customer class to a 4.5% increase. The parties also agreed to a rate of return of 6.98% based upon a 10.2% ROE. The settlement resolved all pending issues related to compliance with the August 25, 2010 Order in the 2008 Electric Rate Case. On December 21, 2011, the IURC issued an Order approving the Settlement Agreement as filed, and new electric base rates became effective on December 27, 2011.

During 2002, NIPSCO settled certain regulatory matters related to an electric rate review. On September 23, 2002, the IURC issued an Order adopting most aspects of the settlement. The Order approving the settlement provided that certain electric customers of NIPSCO would receive bill credits of approximately $55.1 million each year. The credits continued at approximately the same annual level and per the same methodology, until the IURC approval and implementation of new customer rates, which occurred on December 27, 2011. Credits amounting to $51.0 million were recognized for electric customers for 2011. A final reconciliation of the credits was completed in the fourth quarter of 2012, which resulted in recoveries of $6.6 million in 2012.

Cost Recovery and Trackers. A significant portion of NIPSCO'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 NIPSCO. The IURC allows for recovery of such costs via cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO 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.

On December 9, 2009, the IURC issued an Order in its generic DSM investigation proceeding establishing an overall annual energy savings goal of 2% to be achieved by Indiana jurisdictional electric utilities in 10 years, with interim savings goals established in years one through nine. On May 25, 2011, the IURC issued an Order approving a tracker mechanism to recover the costs associated with these energy efficiency programs. On July 27, 2011, the IURC issued an order approving NIPSCO's portfolio of electric energy efficiency programs and on August 8, 2012, approved recovery of lost margins associated with those programs through semi-annual tracker filings.

NIPSCO has approval from the IURC to recover certain environmental related costs through an ECT. Under the ECT, NIPSCO is permitted to recover (1) AFUDC and a return on the capital investment expended by NIPSCO 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 October 30, 2013, the IURC issued an order on ECR-22 approving NIPSCO’s request to begin earning a return on $478.8 million of net capital expenditures. On January 31, 2014, NIPSCO filed ECR-23 which included $583.5 million of net capital expenditures for the period ending December 31, 2013.

On October 10, 2013, the IURC issued an order approving NIPSCO’s MATS Compliance Projects. Refer to Note 20-D, “Environmental Matters,” for additional information on the MATS rule. The Order approved estimated capital costs of $59.3 million and granted the requested ratemaking relief and accounting treatment associated with these projects through the annual EERM and semi-annual ECRM tracker filings.

On March 22, 2011, NIPSCO filed a petition with the IURC for a certificate of public convenience and necessity and associated relief for the construction of additional environmental projects required to comply with the NOV consent decree lodged in the United States District Court for the Northern District of Indiana on January 13, 2011 and EPA Regulations. Refer to Note 20-D, “Environmental Matters,” for additional information. This petition was trifurcated into three separate phases. On December 28, 2011, February 15, 2012 and September 5, 2012, the IURC issued orders approving estimated project costs of approximately $800.0 million and granting the requested ratemaking and accounting relief associated with these projects through annual and semi-annual tracker filings.