Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Stock, $0.01 Par Value: 281,111,006 shares outstanding at September 30, 2011.

The following is a list of frequently used abbreviations or acronyms that are found in this report:


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share amounts)	2011			2010			2011			2010
Net Revenues
Gas Distribution	$	326.7		$	327.0		$	2,199.1		$	2,122.4
Gas Transportation and Storage		283.3			270.7			993.6			905.5
Electric		404.7			397.7			1,101.0			1,056.1
Other		54.0			142.7			235.5			583.9

Gross Revenues		1,068.7			1,138.1			4,529.2			4,667.9
Cost of Sales (excluding depreciation and amortization)		323.1			420.0			1,956.5			2,145.4

Total Net Revenues		745.6			718.1			2,572.7			2,522.5

Operating Expenses
Operation and maintenance		407.1			382.1			1,242.1			1,198.8
Depreciation and amortization		134.9			153.1			408.3			454.5
Impairment and loss on sale of assets, net		0.4			1.1			1.1			1.2
Other taxes		59.2			62.0			220.0			213.4

Total Operating Expenses		601.6			598.3			1,871.5			1,867.9

Equity Earnings in Unconsolidated Affiliates		3.5			3.5			8.8			11.3

Operating Income		147.5			123.3			710.0			665.9

Other Income (Deductions)
Interest expense, net		(95.7	)		(97.6	)		(279.9	)		(294.8	)
Other, net		1.6			2.1			5.5			7.3

Total Other Deductions		(94.1	)		(95.5	)		(274.4	)		(287.5	)

Income from Continuing Operations before Income Taxes		53.4			27.8			435.6			378.4
Income Tax Expense (Benefit)		17.1			(5.6	)		155.0			119.6

Income from Continuing Operations		36.3			33.4			280.6			258.8

Loss from Discontinued Operations—net of taxes		(1.6	)		(0.2	)		(1.8	)		(0.3	)
Gain on Disposition of Discontinued Operations—net of taxes		—			—			—			0.1

Net Income	$	34.7		$	33.2		$	278.8		$	258.6

Basic Earnings (Loss) Per Share
Continuing operations	$	0.13		$	0.12		$	1.00		$	0.93
Discontinued operations		(0.01	)		—			(0.01	)		—

Basic Earnings Per Share	$	0.12		$	0.12		$	0.99		$	0.93

Diluted Earnings (Loss) Per Share
Continuing operations	$	0.13		$	0.12		$	0.98		$	0.93
Discontinued operations		(0.01	)		—			(0.01	)		—

Diluted Earnings Per Share	$	0.12		$	0.12		$	0.97		$	0.93

Dividends Declared Per Common Share	$	0.23		$	0.23		$	0.92		$	0.92

Basic Average Common Shares Outstanding		280.8			278.1			280.1			277.5
Diluted Average Common Shares		289.0			279.9			287.4			278.9

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

The accompanying unaudited condensed consolidated financial statements for NiSource reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America.

The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in NiSource’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although NiSource believes that the disclosures made are adequate to make the information not misleading.

Fair Value Measurements and Disclosures. In January 2010, the FASB issued authoritative guidance that amends the disclosures about transfers into and out of Levels 1 and 2 and requires separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. This guidance also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. This guidance is effective for the first reporting period, including interim periods, beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which is effective for fiscal years beginning after December 15, 2010. Early adoption is permitted. NiSource adopted the guidance on January 1, 2010 with the exception of the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis. The guidance pertaining to the gross presentation of Level 3 activity was adopted on January 1, 2011. Refer to Note 9, “Fair Value Disclosures,” for additional information.

Goodwill Impairment. In September 2011, the FASB issued Accounting Standards Update 2011-08, which gives entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of a reporting unit for the goodwill impairment test. The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. NiSource is currently reviewing the provisions of this new standard to determine the impact on its Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited).

Comprehensive Income. In June 2011, the FASB issued Accounting Standards Update 2011-05, which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in ASC 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The update does not change the items that must be reported in other comprehensive income. For public entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. NiSource is currently reviewing the provisions of this new standard to determine the impact on its Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited).

Basic EPS is computed by dividing income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The weighted average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans and the Forward Agreements (refer to Note 4 “Forward Equity Agreement” for additional information). The calculation of diluted earnings per

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

share for September 30, 2011 and 2010 excludes out-of-the-money stock options that had an anti-dilutive effect. The numerator in calculating both basic and diluted EPS for each period is reported net income. The computation of diluted average common shares follows:

On September 14, 2010, NiSource and Credit Suisse Securities (USA) LLC, as forward seller, closed an underwritten registered public offering of 24,265,000 shares of NiSource’s common stock. All of the shares sold were borrowed and delivered to the underwriters by the forward seller. NiSource did not receive any of the proceeds from the sale of the borrowed shares, but NiSource will receive proceeds upon settlement of the Forward Agreements referred to below.

In connection with the public offering, NiSource entered into forward sale agreements (“Forward Agreements”) with an affiliate of the forward seller covering an aggregate of 24,265,000 shares of NiSource’s common stock. Settlement of the Forward Agreements is expected to occur no later than September 10, 2012. Subject to certain exceptions, NiSource may elect cash or net share settlement for all or a portion of its obligations under the Forward Agreements. Upon any physical settlement of the Forward Agreements, NiSource will deliver shares of its common stock in exchange for cash proceeds at the forward sale price, which initially is $15.9638 and is subject to adjustment as provided in the Forward Agreements. If the equity forward had been settled by delivery of shares at September 30, 2011, NiSource would have received approximately $363.3 million based on a forward price of $14.972 for the 24,265,000 shares. NiSource currently anticipates settling the equity forward by delivering shares.

In accordance with ASC 815-40, NiSource has classified the Forward Agreement as an equity transaction. As a result of this classification, no amounts have been recorded in the Condensed Consolidated Financial Statements (unaudited) as of and for the nine months ended September 30, 2011 and the year ended December 31, 2010 in connection with the Forward Agreements. The only impact to the Condensed Consolidated Financial Statements (unaudited) is the inclusion of incremental shares within the calculation of fully diluted EPS under the treasury stock method. Refer to Note 3, “Earnings Per Share,” for additional information.

The assets of discontinued operations and held for sale on the Condensed Consolidated Balance Sheets (unaudited) at September 30, 2011 were:

There were no liabilities of discontinued operations held for sale at September 30, 2011.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The assets of discontinued operations and held for sale on the Condensed Consolidated Balance Sheets (unaudited) at December 31, 2010 were:

Assets classified as discontinued operations or held for sale are no longer depreciated. There were no liabilities of discontinued operations held for sale at December 31, 2010.

On February 22, 2011, NiSource Corporate Services sold the Marble Cliff facility for $6.0 million. The sale resulted in a net gain of $0.2 million after deducting the fees associated with the transaction.

On June 18, 2009, Columbia Transmission received approval from the FERC to abandon certain natural gas pipeline facilities by sale of its Line R System in West Virginia. Assets held for sale related to the Line R System have a net book value of $2.1 million, the sale of which continues to be negotiated with a third party.

Lake Erie Land, which is a wholly-owned subsidiary of NiSource Development Company, was in the process of selling real estate over a 10-year period as a part of an agreement reached in June 2006 with a private real estate development group. In the second quarter of 2009, the developer was unable to meet certain contractual obligations under the sale agreement and consequently NiSource sought remedial actions. In April 2011, NiSource settled a mortgage foreclosure action against the developer, reacquired the Sand Creek Country Club, and purchased additional properties owned by the developer to be marketed along with the existing Lake Erie Land properties to prospective purchasers. This transaction qualified as a business combination in accordance with GAAP. The properties were acquired at fair value and included the Sand Creek Country Club and additional commercial properties for a total of $15.8 million and $3.5 million of land and are included in Other Investments and Other Property in the Condensed Consolidated Balance Sheet (unaudited) at September 30, 2011. NiSource’s total investment in Lake Erie Land after these acquisitions is $51.3 million as of September 30, 2011. NiSource is seeking to market the Lake Erie Land properties, but has determined they do not meet the criteria to be classified as assets held for sale in accordance with GAAP as of September 30, 2011. The revenue and earnings of Sand Creek Country Club are not material.

Results from discontinued operations, which primarily arise from changes in estimate for certain liabilities for NiSource’s former exploration and production subsidiary, CER, are provided in the following table:

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Certain 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 are classified as “Regulatory liabilities and other removal costs” on the Condensed Consolidated Balance Sheets (unaudited).

Changes in NiSource’s liability for asset retirement obligations for the nine months ended September 30, 2011 and 2010 are presented in the table below:

Significant Rate Developments. On June 1, 2011, Columbia of Virginia filed an application for approval of an infrastructure tracking mechanism pursuant to the Steps to Advance Virginia’s Energy (“SAVE”) Plan Act. Columbia of Virginia’s 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 that would commence on December 30, 2011. The proposed replacement program would result in investments of $20 million per year from 2012 through 2016, as well as covering $2.9 million in investment occurring in 2011. The Staff of the VSCC filed responsive testimony on August 22, 2011 and a public hearing was held on September 7, 2011. The Hearing Examiner issued a Report on October 6, 2011 recommending approval of the substantive provisions of the SAVE Plan. A VSCC Order is due to be issued by November 28, 2011.

On March 8, 2011, Columbia of Kentucky made its annual filing with the Kentucky PSC related to the AMRP Rider and requested an increase of $0.5 million in the rates related to the Rider. This filing was approved by the Kentucky PSC on April 29, 2011.

On January 14, 2011, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $37.8 million annually, and seeking to implement a levelized distribution charge for its residential class that would feature the recovery of all fixed costs through a flat monthly charge. The parties jointly filed a petition for approval of a partial settlement on July 1, 2011. The partial settlement resolved all issues except Columbia of Pennsylvania’s proposed residential rate design and a challenge to the structure of one of Columbia of Pennsylvania’s customer programs. The settlement provides for an annual revenue increase of $17 million. The Pennsylvania PUC issued an order on October 14, 2011 approving the annual revenue increase of $17 million. New rates went into effect on October 18, 2011. The Pennsylvania PUC’s ruling increased the minimum residential customer charge from $12.25 to $18.73, which includes charges for a 20 Ccf monthly usage allowance for residential customers before a volumetric distribution charge is applied.

On November 30, 2010, Columbia of Ohio filed a notice of intent to file an application to adjust rates associated with Rider IRP and Rider DSM. On February 28, 2011, Columbia of Ohio filed its application to adjust rates associated with IRP and DSM Riders. The DSM Rider tracks and recovers costs associated with Columbia of Ohio’s energy efficiency and conservation programs. The application sought to increase the annual revenue from the riders by approximately $24 million. On April 7, 2011, the parties filed a stipulation that settled this case, which was approved as filed by the PUCO on April 27, 2011. The Order allowed Columbia of Ohio to increase its annual revenues by approximately $24 million effective May 1, 2011.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

On November 12, 2010, Columbia of Pennsylvania filed a petition for an order authorizing the company to revise its accounting methodology for the gas it holds in storage. Columbia of Pennsylvania had historically used Last-In First-Out (LIFO) accounting but sought permission to move to a Weighted Average Cost of Gas (WACOG) accounting methodology as a means of simplifying regulatory accounting and to realize the value of low-cost gas injected into storage decades ago. On February 4, 2011, Columbia of Pennsylvania filed a settlement agreement with the Pennsylvania PUC in which regulatory stakeholders agreed that Columbia of Pennsylvania should adopt the WACOG accounting methodology and provide the benefit of the low-cost gas supplies to its customers. On March 31, 2011, the Pennsylvania PUC approved the settlement and Columbia of Pennsylvania began to provide the benefit of $35.7 million as a credit to its customers as a reduction of the GCR rate.

On September 29, 2010, Columbia of Pennsylvania filed tariff modifications with the Pennsylvania PUC, seeking permission to apply a BTU content billing adjustment to customers’ metered volumetric consumption. The filing sought to account for high BTU content gas that is produced from Marcellus Shale, which burns hotter than gas from other sources, resulting in lower volumes than assumed in the design of the Columbia of Pennsylvania’s rates. The proposed billing adjustment was designed to produce revenues reflective of the BTU content underlying the demand forecast in the design of Columbia of Pennsylvania’s most recently approved base rates. If the billing adjustment had been in place for the twelve months ended June 30, 2010, it would have produced additional revenues of approximately $3.7 million. By an Order entered on January 26, 2011, the Pennsylvania PUC consolidated this matter with Columbia of Pennsylvania’s base rate case filed on January 14, 2011. As described above, on October 14, 2011, the Pennsylvania PUC approved a partial settlement of the base rate case. The partial settlement resolves the issue of BTU content whereby Columbia of Pennsylvania will convert from volumetric billing to heat content billing by no later than the June 2012 billing cycle. Columbia of Pennsylvania projects that heat content billing will commence by the February 2012 billing cycle.

On September 1, 2010 Northern Indiana, Northern Indiana Fuel and Light and Kokomo Gas filed a petition for merger into one company (Northern Indiana). Northern Indiana Fuel and Light and Kokomo Gas also filed rate proceedings on September 1, 2010. On February 23, 2011, a stipulation and settlement agreement was filed with the IURC that provides for the merger and settlement of the rate proceedings. The settlement stipulated that all of Northern Indiana’s existing services, rates and charges would be applicable in the former Northern Indiana Fuel and Light and Kokomo Gas territories, including one unified Gas Cost Adjustment mechanism. The application of Northern Indiana’s rates in the former Northern Indiana Fuel and Light and Kokomo Gas territories will result in a decrease in revenue of approximately $0.8 million, when compared to a normalized test year ended March 31, 2010. This is primarily offset by reductions in depreciation expense. An uncontested settlement hearing was held on March 23, 2011. The IURC issued its Final Order on May 31, 2011, approving without change the earlier stipulation and settlement agreement agreed to by the parties. Rates and services provided by the merger agreement became effective July 1, 2011.

On May 3, 2010, Northern Indiana filed a natural gas rate case with the IURC. Northern Indiana entered into a comprehensive settlement with all parties on August 24, 2010. The Settlement Agreement was approved in entirety by Order issued on November 4, 2010 and new rates were placed into effect November 5, 2010. The Order resulted in a decrease in revenue of approximately $14.9 million when compared to a normalized test year ended December 31, 2009. The IURC authorized Northern Indiana to increase the monthly fixed charge for residential customers from $6.36 to $11.00. The IURC also approved revised depreciation accrual rates for gas plant and authorized Northern Indiana to reduce current period gas plant depreciation expense by up to $25.7 million annually for the next four years or until further order of the IURC, whichever occurs first.

On May 3, 2010, Columbia of Virginia filed a base rate case with the VSCC seeking an annual revenue increase of $13.0 million to recover an updated level of costs upon the expiration of its Performance Based Regulation Plan on December 31, 2010. Columbia of Virginia also sought a Weather Normalization Adjustment (“WNA”), cost recovery of certain gas-related items through its Purchased Gas Adjustment (“PGA”) mechanism rather than base rates, and forward looking adjustments predicted to occur during the rate year ending December 31, 2011. On November 16, 2010, Columbia of Virginia, the VSCC Staff and the other parties filed a Proposed Stipulation and Recommendation (“Stipulation”) that would result in an annual revenue increase of $4.9 million, including

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

authorization of the WNA and recovery of certain gas-related items through the PGA mechanism. The Chief Hearing Examiner issued a Report on December 2, 2010 recommending approval of the Stipulation. The VSCC issued a Final Order on December 17, 2010 adopting the Stipulation. New rates became effective January 1, 2011.

On June 27, 2011, Northern Indiana filed a settlement agreement with the IURC in which regulatory stakeholders agreed that Northern Indiana should adopt the WACOG accounting methodology and provide the benefit of the low-cost gas supplies to its customers. Northern Indiana had historically used LIFO accounting methodology. On August 31, 2011, the IURC approved the settlement and Northern Indiana will transition to WACOG accounting methodology beginning January 2012.

Northern Indiana’s current ARP will expire on March 31, 2012 unless extended by the IURC pursuant to the filing. On September 30, 2011 Northern Indiana filed a Petition with the IURC to extend the products and services contained in its current gas ARP, including Supplier Choice effective April 1, 2012. Northern Indiana has been in settlement discussions with the parties and anticipates a final settlement in the fourth quarter of 2011.

On October 21, 2009, the IURC issued an Order in the proceeding concerning Northern Indiana’s annual gas recovery, rejecting the use of a four-year average to compute unaccounted for gas. This Order required Northern Indiana to refund an estimated $5.8 million to customers based on a calculation utilizing a one-year average of unaccounted for gas for the twelve month periods ended July 31, 2008 and July 31, 2009. A reserve was provided for the full amount of the refund, which Northern Indiana began returning to customers in March 2010, and was completed in May 2011.

Columbia of Massachusetts filed an application to implement its Targeted Infrastructure Reinvestment Factor (“TIRF”) on April 30, 2010. On October 29, 2010, the Massachusetts DPU approved Columbia of Massachusetts’ proposed adjustment factor, to take effect November 1, 2010, subject to further investigation and reconciliation. On April 29, 2011, Columbia of Massachusetts filed its second annual application of its TIRF tracker for DPU approval for new rates to go into effect November 1, 2011, and is currently awaiting review and approval by the DPU. On September 16, 2010, Columbia of Massachusetts filed a petition for approval to implement its first semi-annual revenue decoupling adjustment factor (“RDAF”) for the Peak Period. That adjustment, which took effect on November 1, 2010, subject to further review and reconciliation, was approved by the DPU on March 23, 2011. Columbia of Massachusetts filed its application for approval of its Off-peak Period RDAF on March 15, 2011. The rate took effect on May 1, 2011, subject to further review and reconciliation by the DPU. On September 15, 2011, Columbia of Massachusetts filed a petition for approval of its second Peak Period RDAF, with a proposed effective date of November 1, 2011, and is awaiting DPU action with respect to that filing.

In March 2009, Indiana Governor Daniels signed Senate Bill 423 into law giving the Indiana Finance Authority the ability to contract, on behalf of gas customers in the state of Indiana, with developers capable of building facilities that manufacture Substitute Natural Gas from coal. The Indiana Finance Authority (“IFA”) received one bid, from Indiana Gasification, by the April 9, 2009 deadline to initiate a Substitute Natural Gas plant in Southern Indiana under a 30 year contract. In March 2010, Governor Daniels signed into law House Enrolled Act 1086, which allows the IFA to enter into contracts for the sale of Substitute Natural Gas with third parties, with proceeds from and costs of those sales being reflected on customers’ bills. The IURC must approve the final purchase contract between the IFA and Indiana Gasification as well as the management agreement between IFA and the utilities for collection of funds or pass through of credits to customers related to the purchase contracts. On December 16, 2010, the IFA filed a Petition seeking approval of the purchase contract and the management agreement. The IURC held a Prehearing Conference on January 27, 2011, in which a procedural schedule was established. All hearings in this proceeding occurred during two weeks in May 2011 and based upon the schedule it is anticipated that an order will be issued in 2011.

On January 30, 2009, Columbia of Ohio filed an application with the PUCO to implement a gas supply auction. The auction replaced Columbia of Ohio’s current GCR mechanism for providing commodity gas supplies to its sales customers. By Order dated December 2, 2009, the PUCO approved a stipulation that resolved all issues in the case. Pursuant to the stipulation, Columbia of Ohio conducted two consecutive one-year long standard service offer auction periods starting April 1, 2010 and April 1, 2011. On February 23, 2010, Columbia of Ohio held the first standard service offer auction which resulted in a final retail price adjustment of $1.93 per Mcf. On February 24, 2010 the PUCO issued an entry that approved the results of the auction and directed Columbia of Ohio to proceed

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

with the implementation of the standard service offer process. On February 8, 2011, Columbia of Ohio held its second standard service offer auction which resulted in a retail price adjustment of $1.88 per Mcf. On February 9, 2011, the PUCO issued an entry that approved the results of the auction with the new retail price adjustment to become effective April 1, 2011. Columbia of Ohio is scheduled to conduct its first standard choice offer auction in February 2012. Several parties have challenged the transition from a standard service offer auction to a standard choice offer auction and on September 7, 2011, the PUCO issued an Order authorizing Columbia of Ohio to implement a standard choice offer auction in February 2012. On October 7, 2011, the OCC filed an application for rehearing of the PUCO’s Order. Columbia of Ohio filed a memorandum contra on October 17, 2011. NiSource is currently reviewing the impact on its Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited) related to this Order.

On October 3, 2011, Columbia of Ohio filed an application with PUCO, requesting authority to defer incurred charges to a regulatory asset for debt-based post-in-service carrying charges, depreciation and property taxes associated with Columbia of Ohio’s capital program.

On September 9, 2011, Columbia of Ohio filed an application with PUCO to continue and expand its DSM program. In its application, Columbia of Ohio proposes to spend $20 million annually (adjusted for inflation) on weatherization programs for residential and commercial customers for calendar years 2012 through 2016. Columbia of Ohio will continue to recover program expenses through Rider DSM and has proposed a shared savings incentive not to exceed $3.9 million over the five-year program.

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 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.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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 Judge certified the settlement to the FERC as uncontested, and the settlement is now pending a ruling from the FERC.

Significant Rate Developments. On June 27, 2008, Northern Indiana filed a petition with the IURC for new electric base rates and charges. The filing requested an increase in base rates calculated to produce additional gross margin of $85.7 million when compared to a normalized test year ended December 31, 2007. On August 25, 2010, the IURC issued an Order authorizing electric rates to reflect investments in reliability, environmental technology and other infrastructure improvements.

Upon review of the Order, NiSource concluded that the overall impact is in line with the company’s expected outcome for the case and its financial outlook. The IURC approved a rate base of $2,639.0 million and an overall rate of return of 7.29%, which results in an allowed net operating income of $192.4 million. In conjunction with approved expenses, the Order approves rates designed to produce a margin of $899.0 million based on 2007 test year volumes. The approved rate base includes the Sugar Creek Generating Station. Among other findings, the IURC also approved revised depreciation accrual rates for electric and common plant, amortization of deferrals, and two new tracking mechanisms, a Resource Adequacy Tracker and RTO Tracker. The IURC also found that Northern Indiana, before declaring or paying any dividends to NiSource must provide the IURC notice at least 20 business days prior. Northern Indiana provided such notice prior to making any dividend declaration subsequent to the receipt of the August 25, 2010 Order.

Consistent with Northern Indiana’s proposal, the IURC also approved a rate base that excludes Dean H. Mitchell Generating Station and Michigan City Generating Station Units 2 and 3. In accordance with ASC 980, Northern Indiana retired the Dean H. Mitchell Generating Station and Michigan City Generating Station Units 2 and 3 during the third quarter of 2010 as the stations are no longer used and useful. As a result of the Order, construction work in progress, materials and supplies and base coal of $0.6 million, $2.9 million and $0.8 million, respectively were expensed during the third quarter of 2010 as there were no remaining future economic benefits associated with these assets.

Some parties sought reconsideration or rehearing of specific aspects of the case. On April 25, 2011, the IURC issued a docket entry to extend the deemed denied date for reconsideration or rehearing to be 30 days following the IURC’s Order on Northern Indiana’s November 19, 2010 petition for new electric base rates and charges. Several parties have also filed an appeal of the IURC Order to the Indiana Court of Appeals. The appeals are still pending.

As part of the Order, the IURC required Northern Indiana to file a compliance filing with updated tariffs and Northern Indiana made such filing on September 14, 2010. New rates cannot be implemented until the IURC approves the filed tariff. As part of the April 25, 2011 docket entry, the IURC also suspended the compliance filing schedule. Based on this docket entry, Northern Indiana does not believe that rates from the August 25, 2010 IURC Order will be implemented.

Northern Indiana filed a petition for reconsideration with the IURC on September 14, 2010 to clarify that the effective date of certain aspects of the 2008 case including the new depreciation rates, commencement of amortization of deferred balances and discontinuance of further regulatory deferrals and the annual bill credit in effect since 2002 should coincide with the IURC’s approval of new customer rates. On October 22, 2010, the IURC issued a docket entry clarifying that this interpretation is correct.

On November 19, 2010, Northern Indiana filed a petition with the IURC for new electric base rates and charges. The filing requests an increase in base rates calculated to produce additional gross revenue of $75.7 million when compared to a normalized test year ended June 30, 2010. This is calculated to provide the opportunity to earn a return of 7.70% on net original cost rate base of $2,706 million. If approved, the rates from this new petition would replace any other existing rates, including those that may be approved by effect of the August 25, 2010 Order. The proposed rates would ease bill impacts on residential customers, while still allowing Northern Indiana to continue investing in service, reliability and infrastructure improvements. Northern Indiana filed the proceeding under the

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

IURC’s minimum standard filing requirements prescribing timeframes for issuance of an order if required information is supplied as part of the rate case filing. The IURC held its prehearing conference on December 17, 2010 and issued a prehearing conference order on January 5, 2011. The parties agreed to and the IURC ordered a procedural schedule that includes a bifurcated hearing. The evidentiary hearing on the revenue requirement portion of Northern Indiana’s case-in-chief was held on February 28 – March 4, 2011, and the evidentiary hearing on the cost allocation portion of the case was held the week of May 16, 2011.

On July 18, 2011, Northern Indiana filed with the IURC a collaborative settlement in its 2010 Electric Rate Case with the OUCC, Northern Indiana Industrial Group, NLMK Indiana and Indiana Municipal Utilities Group. The provisions of the stipulation and settlement agreement are subject to the review and approval of the IURC. The provisions of the settlement include a revenue requirement of $1,401 million, including other revenue of $46 million for a net revenue requirement of $1,355 million from base rates. The margin, embedded in the $1,401 million, is $926.5 million, as compared to test year actual of $817 million. If the settlement is approved, it would terminate the current customer credit ($59 million reduction in margins during the test year), include two new tracking mechanisms, a Resource Adequacy Tracker and RTO Tracker and lead to the expiration of certain industrial special contracts ($32.8 million reduction in margins during the test year). The settlement agreement will limit the proposed base rate impact to the residential customer class to a 4.5% increase. The parties have also agreed to a rate of return of 6.98% based upon a 10.2% return on equity. The settlement, if approved, would also resolve all pending issues related to compliance with the August 25, 2010 Order in the 2008 Electric Rate Case. On August 19, 2011, the City of Hammond filed testimony in opposition to the settlement. A final hearing was held on September 12, 2011 and September 13, 2011. The settling parties filed their proposed order on September 20, 2011 and the City of Hammond was the only party to file a response which seeks a rejection of the settlement agreement. The settling parties filed a joint reply to the City of Hammond’s response on October 14, 2011. The settlement includes a request by the parties for the IURC to issue an order approving the settlement by December 31, 2011. Northern Indiana is awaiting the Commission order.

Northern Indiana received a favorable regulatory order on February 18, 2009 related to its actions to increase its electric generating capacity and advance its electric rate case. Acting on a settlement reached among Northern Indiana and its regulatory stakeholders, the IURC ruled that Northern Indiana’s Sugar Creek electric generating plant was in service for ratemaking purposes as of December 1, 2008. The IURC also approved the deferral of depreciation expenses and debt-based carrying costs associated with the $330.0 million Sugar Creek investment. Northern Indiana purchased Sugar Creek on May 30, 2008 and effective December 1, 2008, Sugar Creek was accepted as an internal designated network resource within the MISO. The Sugar Creek investment was included in the rate base as part of the IURC’s August 25, 2010 Order. Northern Indiana will continue to defer depreciation expenses and debt-based carrying costs associated with the $330.0 million Sugar Creek investment until the IURC’s approval and implementation of new customer rates. The annual deferral for Sugar Creek is reduced by the annual depreciation on the Mitchell plant of $4.5 million, pursuant to the FAC-71 settlement. The IURC also approved a five year amortization of balances that were deferred as of December 31, 2009 and such amortization will commence with the IURC’s approval and implementation of new customer rates. The same treatment was requested in the 2010 Electric rate case filing.

During 2002, Northern Indiana 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 provides that certain electric customers of Northern Indiana will receive bill credits of approximately $55.1 million each year. The credits will continue at approximately the same annual level and per the same methodology, until the IURC approval and implementation of new customer rates. Credits amounting to $38.6 million and $46.0 million were recognized for electric customers for the nine months ended September 30, 2011 and 2010, respectively.

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. Under the Order, Northern Indiana and other jurisdictional electric utilities must file DSM plans on July 1, 2010, 2013, 2016, and 2019, with annual updates in the interim periods. The IURC requires that certain core programs be established and administered by an independent third party. The IURC did not make any specific findings with respect to cost recovery issues. In compliance with the December 9, 2009 Order, on March 16, 2010 Northern Indiana filed a proposal for a mechanism to recover the costs associated with these energy efficiency programs, including lost revenue. On June

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

17, 2010, Northern Indiana filed for approval of its energy efficiency programs, recovery of program costs and lost revenue, and its proposed performance incentive level and methodology. On May 25, 2011, the IURC issued an Order approving the mechanism to recover the costs associated with these energy efficiency programs. On July 27, 2011, the IURC issued an Order approving the energy efficiency programs. However, the IURC denied lost revenue recovery at this time and Northern Indiana may consider filing with the IURC a request for the recovery of lost revenue once rates and charges become effective in the 2010 Electric Rate Case. The IURC also approved Northern Indiana’s proposal to seek performance incentives after program results can be evaluated based upon evaluation, measurement and verification data. In August 2011, Northern Indiana made its initial filing for recovery of costs incurred and estimated through June 2012. On October 25, 2011 the IURC issued an Order approving the recovery of actual and estimated expenses in the amount of approximately $20 million.

On July 13, 2011, Northern Indiana received approval from the IURC to significantly improve its ability to purchase customer-generated electricity from renewable energy projects. The program, supported by consumer and environmental groups, also allows customers to generate more of their own electricity using renewable energy to reduce their utility costs.

MISO. As part of Northern Indiana’s participation in the MISO transmission service, wholesale energy and ancillary service markets, certain administrative fees and non-fuel costs have been incurred. IURC orders have been issued authorizing the deferral for consideration in a future rate case proceeding of certain non-fuel related costs incurred after Northern Indiana’s rate moratorium, which expired on July 31, 2006. Northern Indiana proposed recovery of the cumulative amount of net non-fuel charges that were deferred as of December 31, 2008, and to recover, through a tracker, charges deferred between December 31, 2008 and the IURC’s approval of new customer rates. During the nine months ended September 30, 2011 and 2010, net MISO costs of $6.6 million and $5.8 million were deferred, respectively. As of September 30, 2011, Northern Indiana had deferred a total of $40.0 million of net MISO costs. In the Order issued on August 25, 2010, the IURC approved an RTO tracker for recovery of MISO non-fuel costs and revenues and off-system sales sharing and ordered that purchased power costs and fuel-related MISO charge types be recovered in the FAC. The IURC also approved a purchase capacity tracker referred to as the Resource Adequacy Tracker. Similar treatment was requested in the 2010 Electric Rate Case filing. The implementation of such trackers coincides with the IURC’s approval and implementation of new customer rates.

MISO and PJM Interconnection undertook a joint effort in April and May 2009 to identify a source of unaccounted flows on several coordinated flowgates. The analysis found that certain PJM Interconnection generating units that were once associated with unit-specific capacity sales were erroneously excluded from PJM Interconnection’s market flows, which significantly affected the congestion price on reciprocally coordinated flowgates on Northern Indiana systems. Higher PJM Interconnection market flows on congested flowgates would have resulted in higher payments to MISO by PJM Interconnection during market-to-market coordination since April 1, 2005. The model was fixed on June 18, 2009. On January 4, 2011, the MISO and PJM Interconnection jointly filed a settlement agreement, which FERC approved on June 16, 2011, to resolve the disputed market-to-market transactions that occurred prior to June, 2009. The settlement agreement provides for a review of existing procedures for implementing the joint operating agreement, a process for reviewing future changes to implementation procedures, and enhanced access to each party’s data. In addition, there was a release and discharge of all claims by any market participant related to the joint operating agreement for all events that occurred prior to the filing of the January 4, 2011 settlement agreement.

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. Various interveners, including the OUCC, had taken issue with the allocation of costs included in Northern Indiana’s FAC-80, FAC-81 and FAC-82, which cover the reconciliation of April through December 2008. The IURC granted a sub-docket to consider such issues in those filings. The intervening parties and Northern Indiana discussed procedures to eliminate these concerns and to resolve them for the historical periods. On November 4, 2009, the IURC approved a settlement agreement which called for a credit of $8.2 million to be provided to FAC customers beginning in November 2009, less any amount for attorney’s fees and expenses. This credit was completed in January 2011.

As part of the August 25, 2010 Order, a new “purchase power benchmark” became effective. This purchase power benchmark superseded the one made effective by a settlement in October 2007. The benchmark is based upon the

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

costs of power generated by a hypothetical natural gas fired unit using gas purchased and delivered to Northern Indiana. During the nine months ended September 30, 2011 and 2010, the amount of purchased power costs exceeding the benchmark amounted to zero and $0.4 million, respectively, which was recognized as a net reduction of revenues.

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 IDEM’s NOx SIP and CAIR and CAMR compliance plan projects through an ECRM and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational through an EERM. The IURC approved the continued use of the ECRM and the EERM trackers in the August 25, 2010 Order and Northern Indiana has requested similar treatment in the November 19, 2010 filing. Upon IURC approval of new customer rates, the cost relating to environmental projects that were in service as of June 30, 2010 will be recovered through base rates and will no longer be tracked through the ECRM and EERM.

The IURC has authorized Northern Indiana to recover costs relating to qualified pollution control projects estimated to cost $514 million, which includes new projects at the R.M. Schahfer Generating Station approved by the IURC’s December 29, 2010 Order. On August 5, 2011 Northern Indiana filed ECR-18, which included $278 million (capital expenditure net of accumulated depreciation) of such capital costs for the period ended June 30, 2011. On March 22, 2011, Northern Indiana 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. Refer to Note 18-C, “Environmental Matters,” for additional information. The evidentiary hearing was held at the IURC on August 31, 2011 addressing the relief regarding (i) the construction of a FGD unit at R.M. Schahfer Generating Station Unit 15 and (ii) a cost estimate increase for the projects approved by the December 29, 2010 Order, which included estimates for a FGD unit at R.M. Schahfer Generating Station Unit 14 and associated common facilities for Units 14 and 15. The evidentiary hearing is scheduled at the IURC for December 14 and 15, 2011, for the balance of the projects associated with the relief requested on March 22, 2011. This includes potential consideration of relief associated with the construction of a FGD unit on Michigan City Generating Station Unit 12. On October 20, 2011 and October 21, 2011, the OUCC and the Industrial Group, respectively, filed testimony in opposition of the proposed construction of a FGD unit on Michigan City Generating Station Unit 12.

NiSource is exposed to certain risks relating to its ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. Derivative natural gas contracts are entered into to manage the price risk associated with natural gas price volatility and to secure forward natural gas prices. Interest rate swaps are entered into to manage interest rate risk associated with NiSource’s fixed-rate borrowings. NiSource designates some of its commodity forward contracts as cash flow hedges of forecasted purchases of commodities and designates its interest rate swaps as fair value hedges of fixed-rate borrowings. Additionally, certain NiSource subsidiaries enter into forward physical contracts with various third parties to procure or sell natural gas or power. Certain forward physical contracts are derivatives which qualify for the normal purchase and normal sales exception which do not require mark-to-market accounting.

Accounting Policy for Derivative Instruments. The ASC topic on accounting for derivatives and hedging requires an entity to recognize all derivatives as either assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) at fair value, unless such contracts are exempted such as a normal purchase and normal sale contract under the provisions of the ASC topic. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation.

NiSource uses a variety of derivative instruments (exchange traded futures and options, physical forwards and options, basis contracts, financial commodity swaps, and interest rate swaps) to effectively manage its commodity price risk and interest rate risk exposure. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, or (b) a hedge of the exposure to variable cash flows of a forecasted transaction. In order for a derivative contract to be designated as a hedge, the relationship between the hedging instrument and the hedged item

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

or transaction must be highly effective. The effectiveness test is performed at the inception of the hedge and each reporting period thereafter, throughout the period that the hedge is designated. Any amounts determined to be ineffective are recognized currently in earnings. For derivative contracts that qualify for the normal purchase and normal sales exception, a contract’s fair value is not recognized in the Consolidated Financial Statements until the contract is settled.

Unrealized and realized gains and losses are recognized each period as components of AOCI, regulatory assets and liabilities or earnings depending on the designation of the derivative instrument. For subsidiaries that utilize derivatives for cash flow hedges, the effective portions of the gains and losses are recorded to AOCI and are recognized in earnings concurrent with the disposition of the hedged risks. If a forecasted transaction corresponding to a cash flow hedge is no longer probable to occur, the accumulated gains or losses on the derivative are recognized currently in earnings. For fair value hedges, the gains and losses are recorded in earnings each period together with the change in the fair value of the hedged item.

As a result of the rate-making process, the rate-regulated subsidiaries generally record gains and losses as regulatory liabilities or assets and recognize such gains or losses in earnings when both the contracts settle and the physical commodity flows. These gains and losses recognized in earnings are then subsequently recovered or passed back to customers in revenues through rates. When gains and losses are recognized in earnings, they are recognized in cost of sales for derivatives that correspond to commodity risk activities and are recognized in interest expense for derivatives that correspond to interest-rate risk activities.

NiSource has elected not to net fair value amounts for its derivative instruments or the fair value amounts recognized for its right to receive cash collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. NiSource discloses amounts recognized for the right to reclaim cash collateral within “Restricted cash” and amounts recognized for the right to return cash collateral within current liabilities on the Consolidated Balance Sheets.

Commodity Price Risk Programs NiSource and NiSource’s utility customers are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. NiSource purchases natural gas for sale and delivery to its retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of NiSource’s utility subsidiaries offer programs where variability in the market price of gas is assumed by the respective utility. The objective of NiSource’s commodity price risk programs is to mitigate this gas cost variability, for NiSource or on behalf of its customers, associated with natural gas purchases or sales by economically hedging the various gas cost components by using a combination of futures, options, forward physical contracts, basis swap contracts or other derivative contracts. Northern Indiana also uses derivative contracts to minimize risk associated with power price volatility. These commodity price risk programs and their respective accounting treatment are described below.

Northern Indiana, Columbia of Pennsylvania, Columbia of Kentucky, Columbia of Maryland and Columbia of Virginia use NYMEX derivative contracts to minimize risk associated with gas price volatility. These derivative programs must be marked to fair value, but because these derivatives are used within the framework of the companies’ GCR or FAC mechanism, regulatory assets or liabilities are recorded to offset the change in the fair value of these derivatives.

Northern Indiana and Columbia of Virginia offer a fixed price program as an alternative to the standard GCR mechanism. These services provide customers with the opportunity to either lock in their gas cost or place a cap on the gas costs that would be charged in future months. In order to hedge the anticipated physical purchases associated with these obligations, forward physical contracts, NYMEX futures and NYMEX options are used to secure forward gas prices. The accounting treatment elected for these contracts is varied whereby certain of these contracts are accounted for as cash flow hedges while some contracts are not. The normal purchase and normal sales exception is elected for forward physical contracts associated with these programs where delivery of the commodity is probable to occur.

Northern Indiana also offers a DependaBill program to its customers as an alternative to the standard tariff rate that is charged to residential customers. The program allows Northern Indiana customers to fix their total monthly bill in

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

future months at a flat rate regardless of gas usage or commodity cost. In order to hedge the anticipated physical purchases associated with these obligations, forward physical contracts, NYMEX futures and NYMEX options have been used to secure forward gas prices. The accounting treatment elected for these contracts is varied whereby certain of these contracts are accounted for as cash flow hedges while some contracts are not. The normal purchase and normal sales exception is elected for forward physical contracts associated with these programs whereby delivery of the commodity is probable to occur.

Northern Indiana enters into gas purchase contracts at first of the month prices that give counterparties the daily option to either sell an additional package of gas at first of the month prices or recall the original volume to be delivered. Northern Indiana charges a fee for this option. The changes in the fair value of these options are primarily due to the changing expectations of the future intra-month volatility of gas prices. These written options are derivative instruments, must be marked to fair value and do not meet the requirement for hedge accounting treatment. However, Northern Indiana records the related gains and losses associated with these transactions as a regulatory asset or liability.

Columbia of Kentucky, Columbia of Ohio, and Columbia of Pennsylvania enter into contracts that allow counterparties the option to sell gas to them at first of the month prices for a particular month of delivery. These Columbia LDCs charge the counterparties a fee for this option. The changes in the fair value of the options are primarily due to the changing expectations of the future intra-month volatility of gas prices. These Columbia LDCs defer a portion of the change in the fair value of the options as either a regulatory asset or liability based on the regulatory customer sharing mechanisms in place, with the remaining changes in fair value recognized currently in earnings.

As part of the MISO Day 2 initiative, Northern Indiana was allocated or has purchased FTRs. These FTRs help Northern Indiana offset congestion costs due to the MISO Day 2 activity. The FTRs are marked to fair value and are not accounted for as a hedge, but since congestion costs are recoverable through the fuel cost recovery mechanism, the related gains and losses associated with marking these derivatives to market are recorded as a regulatory asset or liability. In the second quarter of 2008, MISO changed its allocation procedures from an allocation of FTRs to an allocation of ARRs, whereby Northern Indiana was allocated ARRs based on its historical use of the MISO administered transmission system. ARRs entitle the holder to a stream of revenues or charges based on the price of the associated FTR in the FTR auction, so ARRs can be used to purchase FTRs in the FTR auction. ARRs are not derivatives.

NiSource is in the process of winding down its unregulated natural gas marketing business, where gas financial contracts are utilized to economically hedge expected future gas purchases associated with forward gas agreements. These financial contracts, as well as the associated forward physical sales contracts, are derivatives and are marked-to-market with all associated gains and losses recognized to income. NiSource established reserves of $3.3 million at September 30, 2011 and $6.4 million at December 31, 2010, against certain of these physical sale contract derivatives. These amounts represent reserves related to the creditworthiness of certain customers, the fair value of future cash flows, and the cost of maintaining significant amounts of restricted cash. The physical sales contracts marked-to-market had a fair value gain of approximately $128.9 million at September 30, 2011 and $154.4 million at December 31, 2010, while the financial derivative contracts marked-to-market had a fair value loss of $124.1 million at September 30, 2011 and $137.5 million at December 31, 2010. The $137.5 million loss at December 31, 2010 did not include approximately $10.3 million of January 2011 financial positions as these positions were settled in December 2010.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Commodity price risk program derivative contracted gross volumes are as follows:

Interest Rate Risk Activities. NiSource recognizes that the prudent and selective use of derivatives may help it to lower its cost of debt capital and manage its interest rate exposure. NiSource Finance has entered into various “receive fixed” and “pay floating” interest rate swap agreements which modify the interest rate characteristics of its outstanding long-term debt from fixed to variable rate. These interest rate swaps also serve to hedge the fair market value of NiSource Finance’s outstanding debt portfolio. As of September 30, 2011, NiSource had $6.3 billion of outstanding fixed rate debt, of which $500.0 million is subject to fluctuations in interest rates as a result of the fixed-to-variable interest rate swap transactions. These interest rate swaps are designated as fair value hedges. NiSource had no net gain or loss recognized in earnings due to hedging ineffectiveness for the nine months ended September 30, 2011 and 2010.

On July 22, 2003, NiSource Finance entered into fixed-to-variable interest rate swap agreements in a notional amount of $500 million with four counterparties with an 11-year term. NiSource Finance receives payments based upon a fixed 5.40% interest rate and pays a floating interest amount based on U.S. 6-month BBA LIBOR plus an average of 0.78% per annum. There was no exchange of premium at the initial date of the swaps. In addition, each party has the right to cancel the swaps on July 15, 2013.

Contemporaneously with the issuance on September 16, 2005 of $1 billion of its 5.25% and 5.45% notes, maturing September 15, 2017 and 2020, respectively, NiSource Finance settled $900 million of forward starting interest rate swap agreements with six counterparties. NiSource paid an aggregate settlement payment of $35.5 million which is being amortized from AOCI to interest expense over the term of the underlying debt, resulting in an effective interest rate of 5.67% and 5.88%, respectively. As of September 30, 2011, AOCI includes $11.7 million related to forward starting interest rate swap settlement. These derivative contracts are accounted for as a cash flow hedge.

As of September 30, 2011, NiSource holds a 47.5% interest in Millennium. During 2008, Millennium entered into various interest rate swap agreements in order to protect against the risk of increasing interest rates. During August 2010, Millennium completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million: $375.0 million at 5.33% due June 30, 2027, and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium repaid all outstanding borrowings under the credit agreement, terminated the sponsor guarantee and cash settled the interest rate hedges. These interest rate hedges were accounted for as cash flow hedges by Millennium. As it reports Millennium as an equity method investment, NiSource is required to recognize a proportional share of Millennium’s OCI. NiSource’s proportionate share of the remaining unrealized loss is $20.4 million, net of tax. Millennium is amortizing the unrealized loss related to these terminated interest rate swaps into earnings using the effective interest method through interest expense as interest payments are made. NiSource records its proportionate share of the amortization as Equity Earnings in Unconsolidated Affiliates at the Condensed Statements of Consolidated Income (unaudited).

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

NiSource’s location and fair value of derivative instruments on the Condensed Consolidated Balance Sheets (unaudited) were:

The effect of derivative instruments on the Condensed Statements of Consolidated Income (unaudited) was:

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

It is anticipated that during the next twelve months the expiration and settlement of cash flow hedge contracts will result in income statement recognition of amounts currently classified in AOCI of approximately $0.5 million of loss, net of taxes.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

* For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed in the table above, losses of $9.8 million and $8.8 million for the third quarter of 2011 and 2010, respectively, were deferred as allowed per regulatory orders. These amounts will be amortized to income over future periods of up to twelve months as specified in a regulatory order.

NiSource has not reclassified earnings from AOCI to Cost of Sales due to the probability that certain forecasted transactions would not occur for the nine months ended September 30, 2011 and 2010.

NiSource’s derivative instruments measured at fair value as of September 30, 2011 and December 31, 2010 do not contain any credit-risk-related contingent features.

Certain NiSource affiliates have physical commodity purchase agreements that contain “ratings triggers” that require increases in collateral if the credit rating of NiSource or certain of its affiliates are rated below BBB- by Standard & Poor’s or below Baa3 by Moody’s. These agreements are primarily for the physical purchase or sale of natural gas and electricity. The collateral requirement from a downgrade below the ratings trigger levels would amount to approximately $1.8 million. In addition to agreements with ratings triggers, there are some agreements that contain “adequate assurance” or “material adverse change” provisions that could result in additional credit support such as letters of credit and cash collateral to transact business.

NiSource had $176.6 million and $198.3 million of cash on deposit with brokers for margin requirements associated with open derivative positions reflected within “Restricted cash” on the Condensed Consolidated Balance Sheets (unaudited) as of September 30, 2011 and December 31, 2010, respectively.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on NiSource’s Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2011 and December 31, 2010:

Price risk management assets and liabilities include commodity exchange-traded and non-exchange-based derivative contracts. Exchange-traded derivative contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore nonperformance risk has not been incorporated into these valuations. Certain non-exchange-

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. NiSource uses a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, i.e., inputs derived principally from or corroborated by observable market data by correlation or other means. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures.

To determine the fair value of derivatives associated with NiSource’s unregulated natural gas marketing business, certain reserves were calculated. These reserves were primarily determined by evaluating the credit worthiness of certain customers, fair value of future cash flows, and the cost of maintaining restricted cash. Refer to Note 8, “Risk Management Activities” for additional information on price risk assets.

Price risk management assets also include fixed-to-floating interest-rate swaps, which are designated as fair value hedges, as a means to achieve NiSource’s targeted level of variable-rate debt as a percent of total debt. NiSource uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, as well as market parameters such as current and projected interest rates and volatility. As they are based on observable data and valuations of similar instruments, the interest-rate swaps are categorized in Level 2 in the fair value hierarchy. Credit risk is considered in the fair value calculation of the interest rate swap.

Available-for-sale securities are investments pledged as collateral for trust accounts related to NiSource’s wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). Securities classified within Level 1 include U.S. Treasury debt securities which are highly liquid and are actively traded in over-the-counter markets. NiSource values corporate and mortgage-backed debt securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2. Total gains and losses from available-for-sale securities are included in other comprehensive income (loss). The amortized cost, gross unrealized gains and losses, and fair value of available-for-sale debt securities at September 30, 2011 and December 31, 2010 were:

For the three months ended September 30, 2011 and 2010, the net realized gain on the sale of available-for-sale U.S. Treasury debt securities was $0.1 million and $0.3 million, respectively. For the three months ended September 30, 2011 and 2010, the realized gain on sale of available-for-sale Corporate/Other bond debt securities was $0.1 million and $0.3 million, respectively.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

For the nine months ended September 30, 2011 and 2010, the net realized gain on the sale of available-for-sale U.S. Treasury debt securities was $0.4 million. For the nine months ended September 30, 2011 and 2010, the realized gain on sale of available-for-sale Corporate/Other bond debt securities was $1.0 million.

The cost of maturities sold is based upon specific identification. At September 30, 2011, approximately $2.7 million of U.S. Treasury debt securities have maturities of less than a year while the remaining securities have maturities of greater than one year. At September 30, 2011, approximately $0.6 million of Corporate/Other bonds have maturities of less than a year while the remaining securities have maturities of greater than one year.

NiSource adopted the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which is effective for fiscal years beginning after December 15, 2010, during the first quarter of 2011. The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2011 and 2010:

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

As discussed in Note 8 “Risk Management Activities,” as part of the MISO Day 2 initiative, Northern Indiana obtains FTRs, which help to offset congestion costs due to the MISO Day 2 activity. These instruments are considered derivatives and are classified as Level 3 and reflected in the table above. FTRs are valued using a valuation model based on the value of allocated ARRs and forecasted congestion costs. Since congestion costs are recoverable through the fuel cost recovery mechanism, the related gains and losses associated with marking these derivatives to market are recorded as a regulatory asset or liability. Northern Indiana also writes options for regulatory incentive purposes which are also considered Level 3 valuations. Realized gains and losses for these Level 3 recurring items are included in income within Cost of Sales on the Condensed Statements of Consolidated Income (unaudited). Unrealized gains and losses from Level 3 recurring items are included within Regulatory assets or Regulatory liabilities on the Condensed Consolidated Balance Sheets (unaudited).

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the nine months ended September 30, 2011 and 2010.

B. Other Fair Value Disclosures for Financial Instruments. NiSource has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, restricted cash, accounts receivable, accounts payable, customer deposits and short-term borrowings. NiSource’s long-term borrowings are recorded at historical amounts unless designated as a hedged item in a fair value hedge.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.

Investments. NiSource has corporate owned life insurance which is measured and recorded at cash surrender value. NiSource’s investments in corporate owned life insurance at September 30, 2011 and December 31, 2010 were $24.6 million and $26.0 million, respectively.

Long-term Debt. The fair values of these securities are estimated based on the quoted market prices for the same or similar issues or on the rates offered for securities of the same remaining maturities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The carrying amount and estimated fair values of financial instruments were as follows:

Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). The maximum amount of debt that can be recognized related to NiSource’s accounts receivable programs is $515 million.

All accounts receivables sold to the commercial paper conduits are valued at face value, which approximate fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables sold is determined in part by required loss reserves under the agreements. Below is information about the accounts receivable securitization agreements entered into by NiSource’s subsidiaries.

On October 23, 2009, Columbia of Ohio entered into an agreement to sell, without recourse, substantially all of its trade receivables, as they originate, to CGORC, a wholly-owned subsidiary of Columbia of Ohio. CGORC, in turn, is party to an agreement with BTMU and RBS, also dated October 23, 2009, under the terms of which it sells an undivided percentage ownership interest in its accounts receivable to commercial paper conduits sponsored by BTMU and RBS. On October 21, 2011, the agreement was renewed with an amendment increasing the maximum seasonal program limit from $200 million to $240 million. The amended agreement expires on October 19, 2012, and can be renewed if mutually agreed to by all parties. As of September 30, 2011, $60.0 million of accounts receivable had been transferred by CGORC. CGORC is a separate corporate entity from NiSource and Columbia of Ohio, with its own separate obligations, and upon a liquidation of CGORC, CGORC’s obligations must be satisfied out of CGORC’s assets prior to any value becoming available to CGORC’s stockholder. Under the agreement, an event of termination occurs if NiSource’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB- or Ba3 at either Standard & Poor’s or Moody’s, respectively.

On October 23, 2009, Northern Indiana entered into an agreement to sell, without recourse, substantially all of its trade receivables, as they originate, to NARC, a wholly-owned subsidiary of Northern Indiana. NARC, in turn, is party to an agreement with RBS, also dated October 23, 2009, under the terms of which it sells an undivided percentage ownership interest in its accounts receivable to a commercial paper conduit sponsored by RBS. The maximum seasonal program limit under the terms of the agreement is $200 million. On August 31, 2011, the agreement was renewed, having a new scheduled termination date of August 29, 2012, and can be further renewed if mutually agreed to by both parties. As of September 30, 2011, $125.0 million of accounts receivable had been transferred by NARC. NARC is a separate corporate entity from NiSource and Northern Indiana, with its own separate obligations, and upon a liquidation of NARC, NARC’s obligations must be satisfied out of NARC’s assets prior to any value becoming available to NARC’s stockholder. Under the agreement, an event of termination occurs if Northern Indiana’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB or Ba2 at either Standard & Poor’s or Moody’s, respectively.

On March 15, 2010, Columbia of Pennsylvania entered into an agreement to sell, without recourse, substantially all of its trade receivables, as they originate, to CPRC, a wholly-owned subsidiary of Columbia of Pennsylvania. CPRC, in turn, is party to an agreement with BTMU, also dated March 15, 2010, under the terms of which it sells an undivided percentage ownership interest in its accounts receivable to a commercial paper conduit sponsored by BTMU. The maximum seasonal program limit under the terms of the agreement is $75 million. On March 14, 2011, the agreement was renewed, having a new scheduled termination date of March 13, 2012, and can be further renewed if mutually agreed to by both parties. As of September 30, 2011, $8.2 million of accounts receivable had been transferred by CPRC. CPRC is a separate corporate entity from NiSource and Columbia of Pennsylvania, with its own separate obligations, and upon a liquidation of CPRC, CPRC’s obligations must be satisfied out of CPRC’s assets prior to any value becoming available to CPRC’s stockholder. Under the agreement, an event of termination occurs if NiSource’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB- or Ba3 at either Standard & Poor’s or Moody’s, respectively.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The following table reflects the gross and net receivables transferred as well as short-term borrowings related to the securitization transactions as of September 30, 2011 and December 31, 2010 for Columbia of Ohio, Northern Indiana and Columbia of Pennsylvania:

For the three months ended September 30, 2011 and 2010, $0.7 million and $1.5 million of fees associated with the securitization transactions were recorded as interest expense, respectively. For the nine months ended September 30, 2011 and 2010, $3.0 million and $5.2 million of fees associated with the securitization transactions were recorded as interest expense, respectively. Columbia of Ohio, Northern Indiana and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized and the receivables cannot be sold to another party.

In accordance with the provisions for goodwill accounting under GAAP, NiSource tests its goodwill for impairment annually as of June 30 each year unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component of an operating segment as defined by the FASB.

NiSource’s goodwill assets as of September 30, 2011 were $3.7 billion pertaining primarily to the acquisition of Columbia on November 1, 2000. Of this amount, approximately $2.0 billion is allocated to Columbia Transmission Operations and $1.7 billion is allocated to Columbia Distribution Operations. In addition, Northern Indiana Gas Distribution Operations’ goodwill assets at September 30, 2011 related to the purchase of Northern Indiana Fuel and Light in March 1993 and Kokomo Gas in February 1992 were $18.8 million.

The test performed at June 30, 2011 indicated that the fair value of each of the reporting units that carry or are allocated goodwill exceeded their carrying values, indicating that no impairment exists under Step 1 of the annual impairment test.

NiSource considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of any of the reporting units below their carrying amounts and necessitate another goodwill impairment test. No such indicators were noted that would require goodwill impairment testing during the third quarter.

NiSource’s interim effective tax rates reflect the estimated annual effective tax rates for 2011 and 2010, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2011 and 2010 were 32.0% and (20.1)%, respectively. The effective tax rates for the nine months ended September 30, 2011 and 2010 were 35.6% and 31.6%, respectively. These effective tax rates differ from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences such as the electric production tax deduction provided under Internal Revenue Code Section 199.

In the third quarter of 2010, NiSource recorded a $15.2 million reduction to income tax expense in connection with the Pennsylvania PUC approval of the Columbia of Pennsylvania base rate case settlement on August 18, 2010. The adjustment to income tax expense results from the settlement agreement to flow through in current rates the tax benefits related to a tax accounting method change for certain capitalized costs approved by the Internal Revenue Services

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

On May 12, 2011, the governor of Indiana signed into law House Bill 1004, which among other things, lowers the corporate income tax rate from 8.5% to 6.5% over four years beginning on July 1, 2012. The reduction in the tax rate will impact deferred income taxes and tax related regulatory assets and liabilities recoverable in the rate making process. In addition, other deferred tax assets and liabilities, primarily deferred tax assets related to Indiana net operating loss carryforward, will be reduced to reflect the lower rate at which these temporary differences and tax benefits will be realized. In the second quarter 2011, NiSource recorded tax expense of $6.8 million to reflect the effect of this rate change.

On August 19, 2011, the IRS issued Revenue Procedure 2011-43, which provided a safe harbor method that taxpayers may use to determine whether certain expenditures related to electric transmission and distribution assets must be capitalized. This revenue procedure provided procedures for obtaining automatic consent from the IRS to adopt the safe harbor method for the first or second taxable year beginning after December 31, 2011. NiSource changed its method of tax accounting related to certain expenditures, including those related to electric transmission and distribution assets in 2008. At December 31, 2010, NiSource had $107.4 million of unrecorded tax benefits related to this method change pending resolution on audit or further guidance from the IRS or United States Treasury Department. As a result of the issuance of the revenue procedure NiSource revised its estimates and recorded tax benefits of $12.9 million in the third quarter of 2011. Excluding minor amounts of interest, the revision of estimate did not impact total income tax expense.

There were no material changes recorded in the third quarter of 2011 to NiSource’s uncertain tax positions as of December 31, 2010 except as noted above.

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover its employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for NiSource. The expected cost of such benefits is accrued during the employees’ years of service. Current rates of rate-regulated companies include postretirement benefit costs, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.

For the nine months ended September 30, 2011, NiSource has contributed $142.7 million to its pension plans and $41.4 million to its other postretirement benefit plans.

The following table provides the components of the plans’ net periodic benefits cost for the three and nine months ended September 30, 2011 and 2010:

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

For the quarters ended September 30, 2011 and 2010, pension and other postretirement benefit cost of approximately $13.1 million and $8.3 million, respectively, was capitalized as a component of plant or recognized as a regulatory asset or liability consistent with regulatory orders for certain of NiSource’s regulated businesses. For the nine months ended September 30, 2011 and 2010, pension and other postretirement benefit cost of approximately $21.9 million and $15.4 million, respectively, was capitalized as a component of plant or recognized as a regulatory asset or liability consistent with regulatory orders for certain of NiSource’s regulated business.

On September 1, 2011, NiSource announced that effective August 31, 2011, Christopher A. Helms retired from his position as Executive Vice President and Group CEO of the NiSource Gas Transmission and Storage Group, as well as any other offices or directorships with NiSource or any affiliate. In connection with his retirement from NiSource, NiSource and Mr. Helms entered into a letter agreement on August 30, 2011 (the “Agreement”). The Agreement provided, among other things, for a separation payment plus a lump sum payment for health and welfare benefits, which were accrued at September 30, 2011.

In general, a VIE is an entity which (1) has an insufficient amount of at-risk equity to permit the entity to finance its activities without additional financial subordinated support provided by any parties, (2) whose at-risk equity owners, as a group, do not have power, through voting rights or similar rights, to direct activities of the entity that most significantly impact the entity’s economic performance or (3) whose at-risk owners do not absorb the entity’s losses or receive the entity’s residual return. A VIE is required to be consolidated by a company if that company is determined to be the primary beneficiary of the VIE.

NiSource consolidates those VIEs for which it is the primary beneficiary. Prior to the adoption of the new FASB guidance on consolidation of VIEs, the prevalent method for determining the primary beneficiary was through a quantitative method. With the adoption of the guidance, NiSource also considers qualitative elements in determining the primary beneficiary. These qualitative measures include the ability to control an entity and the obligation to absorb losses or the right to receive benefits.

NiSource’s analysis under this standard includes an assessment of guarantees, operating leases, purchase agreements, and other contracts, as well as its investments and joint ventures. For items that have been identified as variable interests, or where there is involvement with an identified VIE, an in-depth review of the relationship between the relevant entities and NiSource is made to evaluate qualitative and quantitative factors to determine the primary beneficiary, if any, and whether additional disclosures would be required under the current standard.

At September 30, 2011, consistent with prior periods, NiSource consolidated its low income housing real estate investments from which NiSource derives certain tax benefits. Based on the newly adopted guidance on the consolidation of variable interest entities, these investments met the definition of a VIE. As of September 30, 2011, NiSource is a 99% limited partner with a net investment of approximately $1.2 million. Consistent with prior periods, NiSource evaluated the nature and intent of the low income housing investments when determining the

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

primary beneficiary. NiSource concluded that it continues to be the primary beneficiary. Subject to certain conditions precedent, NiSource has the contractual right to take control of the low income housing properties. At September 30, 2011, gross assets of the low income housing real estate investments in continuing operations were $29.0 million. Current and non-current assets were $1.4 million and $27.6 million, respectively. As of September 30, 2011, NiSource recorded long-term debt of approximately $11.3 million as a result of consolidating these investments. However, this debt is nonrecourse to NiSource and NiSource’s direct and indirect subsidiaries. Approximately $0.7 million of the assets are restricted to settle the obligations of the entity.

Northern Indiana has a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provides scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services under this contract commenced on July 1, 1992, and Northern Indiana pays for the services under a combination of fixed and variable charges. The agreement provides that, assuming various performance standards are met by Pure Air, a termination payment would be due if Northern Indiana terminated the agreement prior to the end of the twenty-year contract period. NiSource has made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, Northern Indiana had not been able to obtain this information and as a result, it is unclear whether Pure Air is a VIE and if Northern Indiana is the primary beneficiary. Northern Indiana will continue to request the information required to determine whether Pure Air is a VIE. Northern Indiana has no exposure to loss related to the service agreement with Pure Air.

During July 2011, Northern Indiana redeemed $18.7 million of its medium-term notes, with an average interest rate of 7.30%.

On June 10, 2011, NiSource Finance issued $400.0 million of 5.95% senior unsecured notes that mature June 15, 2041.

On December 8, 2010, NiSource Finance issued $250.0 million of 6.25% senior unsecured notes that mature December 15, 2040.

On December 1, 2010, NiSource Finance announced that it was commencing a cash tender offer for up to $250.0 million aggregate principal amount of its outstanding 10.75% notes due 2016 and 6.80% notes due 2019. A condition of the offering was that all validly tendered 2016 notes would be accepted for purchase before any 2019 notes were accepted. On December 14, 2010, NiSource Finance announced that approximately $272.9 million of the aggregate principal amount of its outstanding 10.75% notes due 2016 were validly tendered. Based upon the principal amount of the 2016 notes tendered, NiSource Finance increased the maximum aggregate principal amount of 2016 notes it would purchase from $250.0 million to $325.0 million and terminated the portion of the tender offer related to its 6.80% notes due 2019. On December 30, 2010, NiSource Finance announced that $273.1 million of these notes were successfully tendered. In accordance with the provisions of ASC 470, Debt, NiSource determined the new 6.25% notes due 2040 to be substantially different from the old debt instrument, and therefore the transaction qualified as a debt extinguishment. NiSource recorded a $96.7 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums and unamortized discounts and fees.

On November 15, 2010, NiSource Finance redeemed $681.8 million of its 7.875% unsecured notes.

During June 2011, NiSource Finance implemented a new commercial paper program with a program limit of up to $500.0 million with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. Commercial paper issuances are supported by available capacity under NiSource’s $1.5 billion unsecured revolving credit facility, which expires in March 2015. At September 30, 2011, NiSource had $425.8 million of commercial paper outstanding.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

On March 3, 2011, NiSource Finance entered into a new $1.5 billion four-year revolving credit facility with a syndicate of banks led by Barclays Capital. The new facility has a termination date of March 3, 2015 and replaced an existing $1.5 billion five-year credit facility which would have expired during July 2011. The purpose of the facility is to fund ongoing working capital requirements and for general corporate purposes, including supporting liquidity for NiSource’s commercial paper program, and provides for the issuance of letters of credit. At September 30, 2011, NiSource had $615.0 million of outstanding borrowings under this facility.

As of September 30, 2011 and December 31, 2010, NiSource had $37.4 million and $32.5 million, respectively, of stand-by letters of credit outstanding, of which $19.2 million and $14.2 million, respectively, were under the revolving credit facility.

Beginning January 1, 2010, transfers of accounts receivable that previously qualified for sales accounting no longer qualify and are accounted for as secured borrowings resulting in the recognition of short-term debt on the Condensed Consolidated Balance Sheet in the amount of $193.2 million and $275.0 million as of September 30, 2011 and December 31, 2010, respectively. Refer to Note 10, “Transfers of Financial Assets,” for additional information.

Given their turnover is less than 90 days, cash flows related to the borrowings and repayments of the items listed above are presented net at the Condensed Statements of Consolidated Cash Flows (unaudited).

Prior to May 11, 2010, NiSource issued long-term incentive grants to key management employees under a long-term incentive plan approved by stockholders on April 13, 1994 (“1994 Plan”). The 1994 Plan, as amended and restated, permits the following types of grants, separately or in combination: nonqualified stock options, incentive stock options, restricted stock awards, stock appreciation rights, restricted stock units, contingent stock units and dividend equivalents payable on grants of options, performance units and contingent stock awards.

The stockholders approved and adopted the NiSource Inc. 2010 Omnibus Incentive Plan (the “Omnibus Plan”), at the Annual Meeting of Stockholders held on May 11, 2010. The Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 8,000,000 plus the number of shares subject to outstanding awards granted under either the 1994 Plan or the Director Plan (described below) that expire or terminate for any reason and no further awards are permitted to be granted under the 1994 Plan or the Director Plan. The types of awards authorized under the Omnibus Plan do not significantly differ from those previously allowed under the 1994 Plan. At September 30, 2011, there were 7,992,445 shares reserved for future awards under the Omnibus Plan.

NiSource recognized stock-based employee compensation expense of $4.0 million and $3.0 million for the three months ended September 30, 2011 and 2010, respectively, as well as related tax benefits of $1.3 million and $0.7 million. For the nine months ended September 30, 2011 and 2010, stock-based employee compensation expense of $10.2 million and $9.0 million was recognized, respectively, as well as related tax benefits of $3.6 million and $2.8 million, respectively.

As of September 30, 2011, the total remaining unrecognized compensation cost related to nonvested awards amounted to $17.8 million, which will be amortized over the weighted-average remaining requisite service period of 1.9 years.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Stock Options. As of September 30, 2011, approximately 3.2 million options were outstanding and exercisable with a weighted average strike price of $22.01.

Restricted Awards. During the nine months ended September 30, 2011, NiSource granted 141,544 restricted stock units, subject to service conditions, at a total grant date fair value of $2.4 million, based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting period, which will be expensed, net of forfeitures, over the vesting period of approximately three years. The service conditions for 119,308 units lapse in January 2014 when 100% of the shares vest. If before January 2014, the employee terminates employment (1) due to retirement, having attained age 55 and completed ten years of service, or (2) due to death or disability, the employment conditions will lapse with respect to a pro rata portion of the restricted units on the date of termination. Termination due to any other reason will result in all restricted units awarded being forfeited effective the employee’s date of termination. Employees will be entitled to receive dividends upon vesting. The service conditions lapse for the remaining 22,236 units between March 2012 and July 2014. As of September 30, 2011, 702,298 nonvested restricted stock units were granted and outstanding.

Contingent Stock Units. During the nine months ended September 30, 2011, NiSource granted 745,042 contingent stock units subject to performance conditions, at a grant date fair-value of $11.9 million, based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. The performance conditions are based on achievement of non-GAAP financial measures. The service conditions lapse on January 31, 2014 when 100% of the shares vest. If the employee terminates employment before January 31, 2014 (1) due to retirement, having attained age 55 and completed ten years of service, or (2) due to death or disability, the employment conditions will lapse with respect to a pro rata portion of the contingent units on the date of termination. Termination due to any other reason will result in all contingent units awarded being forfeited effective the employee’s date of termination. Employees will be entitled to receive dividends upon vesting. As of September 30, 2011, 2,234,744 nonvested contingent stock units were granted and outstanding.

Non-employee Director Awards. As of May 11, 2010, awards to non-employee directors may be made only under the NiSource Inc. 2010 Omnibus Incentive Plan (the “Omnibus Plan”). The Omnibus Plan provides for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock and restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. Currently, restricted stock units are granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s restricted stock units vest on the last day of the non-employee director’s annual term corresponding to the year the restricted stock units were awarded subject to special pro-rata vesting rules in the event of Retirement or Disability (as defined in the award agreement), or death. The vested restricted stock units are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. As of September 30, 2011, 110,178 restricted stock units had been issued under the Omnibus Plan.

Only restricted stock units remain outstanding under the prior plan for non-employee directors, the Amended and Restated Non-employee Director Stock Incentive Plan (the “Director Plan”). All such awards are fully vested and shall be distributed to the directors upon their separation from the Board. As of September 30, 2011, 274,315 restricted stock units remain outstanding under the Director Plan and as noted above no further shares may be issued under the Director Plan.

401(k) Match, Profit Sharing and Non-Discretionary Employer Contribution for Certain Employees. NiSource has a voluntary 401(k) savings plan covering eligible employees that allows for periodic discretionary matches as a percentage of each participant’s contributions in newly issued shares of common stock. NiSource also has a retirement savings plan that provides for discretionary profit sharing contributions of shares of common stock to eligible employees based on earnings results and a non-discretionary employer contribution of 3% for salaried employees hired after January 1, 2010 payable in shares of common stock. For the quarter ended September 30, 2011 and 2010, NiSource recognized 401(k) match, profit sharing and non-discretionary employer contribution expense of $6.5 million and $4.4 million, respectively. For the nine months ended September 30, 2011 and 2010, NiSource recognized 401(k) match, profit sharing and non-discretionary employer contribution expense of $17.2 million and $14.2 million, respectively.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

A. Guarantees and Indemnities. As a part of normal business, NiSource and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. The total commercial commitments in existence at September 30, 2011 and the years in which they expire were:

Guarantees of Subsidiaries Debt. NiSource has guaranteed the payment of $5.9 billion of debt for various wholly- owned subsidiaries including NiSource Finance and Columbia of Massachusetts, and through a support agreement, Capital Markets, which is reflected on NiSource’s Condensed Consolidated Balance Sheets (unaudited). The subsidiaries are required to comply with certain covenants under the debt indenture and in the event of default, NiSource would be obligated to pay the debt’s principal and related interest. NiSource does not anticipate its subsidiaries will have any difficulty maintaining compliance. On October 3, 2011, NiSource executed a Second Supplemental Indenture to the original Columbia of Massachusetts Indenture dated April 1, 1991, for the specific purpose of guarantying Columbia of Massachusetts’ outstanding medium-term notes.

Guarantees Supporting Commodity Transactions of Subsidiaries. NiSource has issued guarantees, which support up to $149.9 million of commodity-related payments for its current subsidiaries involved in energy related activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions involving natural gas. To the extent liabilities exist under the commodity-related contracts subject to these guarantees, such liabilities are included in the Condensed Consolidated Balance Sheets (unaudited).

Lines and Letters of Credit and Accounts Receivable Advances. On March 3, 2011, NiSource Finance entered into a new $1.5 billion four-year revolving credit facility with a syndicate of banks led by Barclays Capital. The new facility replaced an existing $1.5 billion five-year credit facility which would have expired during July 2011. The new facility has a termination date of March 3, 2015. The purpose of the facility is to fund ongoing working capital requirements and for general corporate purposes, including supporting liquidity for the Company’s commercial paper program, and provides for the issuance of letters of credit. At September 30, 2011, NiSource had $615.0 million in borrowings under its four-year revolving credit facility, $425.8 million in commercial paper outstanding and $193.2 million outstanding under its accounts receivable securitization agreements. At September 30, 2011, NiSource issued stand-by letters of credit of approximately $37.4 million for the benefit of third parties. See Note 16, “Short-Term Borrowings,” for additional information.

Other Guarantees or Obligations. On June 30, 2008, NiSource sold Whiting Clean Energy to BPAE for $216.7 million which included $16.1 million in working capital. The agreement with BPAE contains representations, warranties, covenants and closing conditions. NiSource has executed purchase and sales agreement guarantees totaling $220 million which guarantee performance of PEI’s covenants, agreements, obligations, liabilities, representations and warranties under the agreement with BPAE. No amounts related to the purchase and sales agreement guarantees are reflected in the Condensed Consolidated Balance Sheet (unaudited) as of September 30, 2011. These guarantees are due to expire in June 2013.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

NiSource has additional purchase and sales agreement guarantees totaling $30.0 million, which guarantee performance of the seller’s covenants, agreements, obligations, liabilities, representations and warranties under the agreements. No amounts related to the purchase and sales agreement guarantees are reflected in the Condensed Consolidated Balance Sheets (unaudited). Management believes that the likelihood NiSource would be required to perform or otherwise incur any significant losses associated with any of the aforementioned guarantees is remote.

In connection with Millennium’s refinancing of its long-term debt in August 2010, NiSource provided a letter of credit to Union Bank N.A., as Collateral Agent for deposit into a debt service reserve account as required under the Deposit and Disbursement Agreement governing the Millennium notes offering. This account is to be drawn upon by the note holders in the event that Millennium is delinquent on its principal and interest payments. The value of NiSource’s letter of credit represents 47.5% (NiSource’s ownership percentage in Millennium) of the Debt Service Reserve Account requirement, or $16.2 million. The total exposure for NiSource is $16.2 million. NiSource recorded an accrued liability of $1.5 million related to the inception date fair value of this guarantee as of September 30, 2011.

NiSource has issued other guarantees supporting derivative related payments associated with interest rate swap agreements issued by NiSource Finance, operating leases for many of its subsidiaries and for other agreements entered into by its current and former subsidiaries.

B. Other Legal Proceedings. In the normal course of its business, NiSource and its subsidiaries have been named as defendants in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material impact on NiSource’s consolidated financial position.

Tawney, et al. v. Columbia Natural Resources, Inc., Roane County, WV Circuit Court

The Plaintiffs, who are West Virginia landowners, filed a lawsuit in early 2003 in the West Virginia Circuit Court for Roane County, West Virginia (the “Trial Court”) against CNR alleging that CNR underpaid royalties on gas produced on their land by improperly deducting post-production costs and not paying a fair value for the gas. Plaintiffs also claimed that Defendants fraudulently concealed the deduction of post-production charges. In December 2004, the Trial Court granted Plaintiffs’ motion to add NiSource and Columbia as Defendants. The Trial Court later certified the case as a class action that includes any person who, after July 31, 1990, received or is due royalties from CNR (and its predecessors or successors) on lands lying within the boundary of the state of West Virginia. Although NiSource sold CNR in 2003, NiSource remained obligated to manage this litigation and was responsible for the majority of any damages awarded to Plaintiffs. On January 27, 2007, the jury hearing the case returned a verdict against all Defendants in the amount of $404.3 million inclusive of both compensatory and punitive damages; Defendants subsequently filed their Petition for Appeal, which was later amended, with the West Virginia Supreme Court of Appeals (the “Appeals Court”), which refused the petition on May 22, 2008. On August 22, 2008, Defendants filed Petitions to the United States Supreme Court for writ of certiorari. Given the Appeals Court’s earlier refusal of the appeal, NiSource adjusted its reserve in the second quarter of 2008 to reflect the portion of the Trial Court judgment for which NiSource would be responsible, inclusive of interest. This amount was included in “Legal and environmental reserves,” on the Consolidated Balance Sheet as of December 31, 2008. On October 24, 2008, the Trial Court preliminarily approved a Settlement Agreement with a total settlement amount of $380 million. The settlement received final approval by the Trial Court on November 22, 2008. NiSource’s share of the settlement liability is up to $338.8 million. On June 21, 2011, the Court issued the Second Supplemental Order to conclude administration of settlement. The Order sets forth the specific steps to be taken by the Parties to close administration of the settlement and terminate the settlement fund. As of September 30, 2011, NiSource funded all claims tendered by the Claims Administrator. NiSource does not expect to make additional material payments in this matter.

On September 29, 2004, the EPA issued an NOV to Northern Indiana for alleged violations of the CAA and the Indiana SIP. The NOV alleges that modifications were made to certain boiler units at three of Northern Indiana’s generating stations between the years 1985 and 1995 without obtaining appropriate air permits for the modifications. Northern Indiana, EPA, Department of Justice, and IDEM have settled the matter.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The consent decree was entered by the United States District Court for the Northern District of Indiana on July 22, 2011. The consent decree covers Northern Indiana’s four coal generating stations: Bailly, Michigan City, R.M. Schahfer, and D.H. Mitchell. Northern Indiana must surrender environmental permits for D.H. Mitchell’s coal-fired boilers, which have not been used to generate power since 2002. At the other generating stations, Northern Indiana must install additional control equipment, including three new SO2 control devices and one new NOx control device. The consent decree also imposes emissions limits for NOx, SO2, and particulate, and annual tonnage limits for NOx and SO2. In addition, Northern Indiana paid fines of $3.5 million in the third quarter of 2011, must surrender certain NOx and SO2 allowances, and invest $9.5 million in environmental mitigation projects. Northern Indiana estimates the cost of NSR related capital improvements at $570 to $845 million, which will be expended between 2010 and 2018. Northern Indiana believes the capital costs will likely be recoverable from ratepayers.

NiSource operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. NiSource believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary permits to conduct its operations.

It is management’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment and remediation costs to be recoverable through rates for certain NiSource companies.

As of September 30, 2011 and December 31, 2010, NiSource had recorded reserves of approximately $105.7 million and $79.8 million, respectively, to cover environmental remediation at various sites. NiSource accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, and the method of cleanup. These expenditures are not currently estimable at some sites. NiSource periodically adjusts its reserves as information is collected and estimates become more refined.

The actions listed below could require further reductions in emissions from various emission sources. NiSource will continue to closely monitor developments in these matters.

Climate Change. Future legislative and regulatory programs could significantly restrict emissions of GHGs or could impose a cost or tax on GHG emissions. Recently, proposals have been developed to implement Federal, state and regional GHG programs and to create renewable energy standards.

In 2009 and 2010, the United States Congress considered a number of legislative proposals to regulate GHG emissions. The United States House of Representatives passed a comprehensive climate change bill in June 2009 that would have created a GHG cap-and-trade system and implemented renewable energy standards. Bills on the same topics were introduced in the Senate in 2009 and 2010, but failed to garner enough support to pass.

If a Federal or state comprehensive climate change bill were to be enacted into law, the impact on NiSource’s financial performance would depend on a number of factors, including the overall level of required GHG reductions, the renewable energy targets, the degree to which offsets may be used for compliance, the amount of recovery allowed from customers, and the extent to which NiSource would be entitled to receive CO 2 allowances at no cost. Comprehensive Federal or state GHG regulation could result in additional expense or compliance costs that may not be fully recoverable from customers and could materially impact NiSource’s financial results.

National Ambient Air Quality Standards. The CAA requires EPA to set national air quality standards for particulate matter and five other pollutants (the NAAQS) considered harmful to public health and the environment. Periodically EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by electric generation, gas distribution, and gas transmission operations.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Particulate Matter: In 2006, the EPA issued revisions to the NAAQS for particulate matter. The final rule (1) increased the stringency of the current fine particulate (PM2.5) standard, (2) added a new standard for inhalable coarse particulate (particulate matter between 10 and 2.5 microns in diameter), and (3) revoked the annual standards for coarse particulate (PM10) while retaining the 24-hour PM10 standards. These actions were challenged in a case before the DC Court of Appeals, American Farm Bureau Federation et al. v. EPA. In 2009, the appeals court granted portions of the plaintiffs’ petitions challenging the fine particulate standards but denied portions of the petitions challenging the standards for coarse particulate. State plans implementing the new standard for inhalable coarse particulate and the modified 24-hour standard for fine particulate are expected in 2012. The annual and secondary PM2.5 standards have been remanded to the EPA for reconsideration.

Ozone (eight hour): On September 2, 2011, the EPA announced it would implement its 2008 eight-hour ozone NAAQS rather than tightening the standard in 2012. The EPA will review, and possibly revise, the standard in 2013 consistent with CAA requirements. Northern Indiana will continue to monitor this matter and cannot estimate the impact of any new rules at this time.

Nitrogen Dioxide (NO2): The EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some NiSource combustion sources. EPA will designate areas that do not meet the new standard beginning in 2012. States with areas that do not meet the standard will need to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances emissions from some existing NiSource combustion sources may need to be assessed and compared to the revised NO2 standards before areas are designated. Petitions challenging the rule have been filed by various parties. NiSource will continue to monitor this matter and cannot estimate the impact of the rules at this time.

National Emission Standard for Hazardous Air Pollutants. On August 20, 2010, the EPA revised national emission standards for hazardous air pollutants for certain stationary reciprocating internal combustion engines. Compliance requirements vary by engine type and will generally be required within three years. NiSource is continuing its evaluation of the cost impacts of the final rule and estimates the cost of compliance to be $20 to $25 million.

NiSource subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws. Additionally, a program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified up to 84 such sites and initial investigations have been conducted at 56 sites. Follow-up investigation activities have been completed or are in progress at 50 sites and remedial measures have been implemented or completed at 37 sites. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements. The final costs of cleanup have not yet been determined. In the fourth quarter of 2011, NiSource plans to evaluate of all such sites for which remediation is not yet complete. As the evaluations, site investigations and cleanups proceed, reserves could increase or otherwise be adjusted to reflect new information.

The sections above describe various regulatory actions that affect Gas Transmission and Storage Operations, Electric Operations, and certain other discontinued operations for which we have retained a liability. Specific information is provided below.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Columbia Transmission continues to conduct characterization and remediation activities at specific sites under a 1995 AOC (subsequently modified in 1996 and 2007). The 1995 AOC originally covered 245 major facilities, approximately 13,000 liquid removal points, approximately 2,200 mercury measurement stations and about 3,700 storage well locations. As a result of the 2007 amendment, approximately 50 facilities remain subject to the terms of the AOC. During the third quarter of 2011, Columbia Transmission completed a study to estimate its future remediation requirements related to the AOC. Columbia Transmission accordingly increased its liability for estimated remediation costs by $25.6 million. The total liability at Columbia Transmission related to the facilities subject to remediation was $33.7 million and $9.5 million at September 30, 2011 and December 31, 2010, respectively. The liability represents Columbia Transmission’s best estimate of the cost to remediate the facilities or manage the sites until retirement. A Response Action Work Plan consistent with this estimate was submitted to the EPA in October 2011. Remediation costs are estimated based on the information available, applicable remediation standards, and experience with similar facilities. Columbia Transmission expects that the remediation for these facilities will be completed in 2015.

One of the facilities subject to the 1995 AOC is the Majorsville Operations Center, which was remediated under an EPA approved Remedial Action Work Plan in the summer of 2008. Pursuant to the Remedial Action Work Plan, Columbia Transmission completed a project that stabilized residual oil contained in soils at the site and in sediments in an adjacent stream. Columbia Transmission continues to monitor the site subject to EPA oversight. On April 23, 2009, PADEP issued an NOV to Columbia Transmission, alleging that the remediation did not fully address the contamination. The NOV asserts violations of the Pennsylvania Clean Streams Law and the Pennsylvania Solid Waste Management Act and includes a proposed penalty of $1 million. Columbia Transmission is unable to estimate the likelihood or cost of potential penalties or additional remediation at this time.

Northern Indiana expects to become subject to a number of new air-quality mandates in the next several years. These mandates may require Northern Indiana to make capital improvements to its electric generating stations. The cost of capital improvements is estimated to be $620 to $995 million. This figure includes additional capital improvements associated with the Cross-State Air Pollution Rule (CSAPR) and the proposed Utility Hazardous Air Pollutants Rule. Northern Indiana believes that the capital costs will likely be recoverable from ratepayers.

Sulfur dioxide: On December 8, 2009, the EPA revised the SO2 NAAQS by adopting a new 1-hour primary NAAQS for sulfur dioxide (SO2). EPA expects to designate areas that do not meet the new standard by mid-2012. States with such areas would have until 2014 to develop attainment plans with compliance required by 2017. Northern Indiana will continue to monitor developments in these matters but does not anticipate a material impact.

Clean Air Interstate Rule (CAIR) / Transport Rule/ Cross-State Air Pollution Rule: On July 6, 2011, the EPA announced its replacement for the 2005 CAIR to reduce the interstate transport of fine particulate matter and ozone. The CSAPR reduces overall emissions of SO2 and NOx by setting state-wide caps on power plant emissions. The CSAPR limits emissions, including Northern Indiana’s, with restricted emission allowance trading programs beginning in 2012. Emission allowances issued under the CAIR program will be eliminated as of January 1, 2012. Northern Indiana utilized the inventory model in accounting for emission allowances issued under the CAIR program whereby these allowances were recognized at zero cost upon receipt from the EPA. Northern Indiana believes its current multi-pollutant compliance plan and NOV capital investments will allow Northern Indiana to meet the emission requirements of CSAPR in 2012.

Utility Hazardous Air Pollutants: On February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit vacated two EPA rules that are the basis for the Indiana Air Pollution Control Board’s Clean Air Mercury Rule (CAMR) that established utility mercury emission limits in two phases (2010 and 2018) and a cap-and-trade program to meet those limits. In response to the vacatur, the EPA is pursuing a new Section 112 rulemaking to establish MACT standards for electric utilities. EPA announced its proposal on March 16, 2011 and intends to finalize the rule by November 2011. Northern Indiana will continue its evaluation and monitoring of this matter.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

New Source Review: On September 29, 2004, the EPA issued an NOV to Northern Indiana for alleged violations of the CAA and the Indiana SIP. The NOV alleges that modifications were made to certain boiler units at three of Northern Indiana’s generating stations between the years 1985 and 1995 without obtaining appropriate air permits for the modifications. Northern Indiana, EPA, the Department of Justice, and IDEM have settled the matter.

The consent decree was entered by the United States District Court for the Northern District of Indiana on July 22, 2011. The consent decree covers Northern Indiana’s four coal generating stations: Bailly, Michigan City, R.M. Schahfer, and D.H. Mitchell. Northern Indiana must surrender environmental permits for D.H. Mitchell’s coal-fired boilers, which have not been used to generate power since 2002. At the other generating stations, Northern Indiana must install additional control equipment, including three new scrubbers to control sulfur dioxide (“SO2”) and one new nitrogen oxide (“NOx”) control device. The consent decree also imposes emissions limits for NOx, SO2, and particulate matter, and annual tonnage limits for NOx and SO2. In addition, Northern Indiana paid fines of $3.5 million in the third quarter of 2011, must surrender certain NOx and SO2 allowances, and invest $9.5 million in environmental mitigation projects. Northern Indiana is estimating the cost of NSR related capital improvements at $570 to $845 million which will be expended between 2010 and 2018. Northern Indiana believes the capital costs will likely be recoverable from ratepayers.

The Phase II Rule of the Clean Water Act Section 316(b), which requires all large existing steam electric generating stations to meet certain performance standards to reduce the effects on aquatic organisms at their cooling water intake structures, became effective on September 7, 2004. Under this rule, stations will either have to demonstrate that the performance of their existing fish protection systems meet the new standards or develop new systems, such as a closed-cycle cooling tower. Various court challenges and EPA responses ensued. The EPA announced a proposed rule and is obligated to finalize a rule in 2012. Northern Indiana will continue to monitor this matter but cannot estimate the cost of compliance at this time.

On March 31, 2005, the EPA and Northern Indiana entered into an AOC under the authority of Section 3008(h) of the RCRA for the Bailly Station. The order requires Northern Indiana to identify the nature and extent of releases of hazardous waste and hazardous constituents from the facility. Northern Indiana must also remediate any release of hazardous constituents that present an unacceptable risk to human health or the environment. The process to complete investigation and select appropriate remediation activities is ongoing. The final costs of cleanup could change based on EPA review.

On June 21, 2010, EPA published a proposed rule for coal combustion residuals through the RCRA. The proposal outlines multiple regulatory approaches that EPA is considering. These proposed regulations could negatively affect Northern Indiana’s ongoing byproduct reuse programs and would impose additional requirements on its management of coal combustion residuals. Northern Indiana will continue to monitor developments in this matter but cannot estimate the cost of compliance at this time.

NiSource affiliates have retained environmental liabilities, including cleanup liabilities associated with some of their former operations. Four sites are associated with former propane operations and ten sites associated with former petroleum operations. At one of those sites, an AOC has been signed with EPA to address petroleum residue in soil and groundwater.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The following table displays the components of Accumulated Other Comprehensive Loss.

During 2008, Millennium, in which Columbia Transmission has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420.0 million with seven counterparties. During August 2010, Millennium completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million: $375.0 million at 5.33% due June 30, 2027, and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium repaid all outstanding borrowings under the credit agreement, terminated the sponsor guarantee, and cash settled the interest rate hedges. These interest rate swap derivatives were accounted for as cash flow hedges by Millennium. As Millennium is an equity method investment, NiSource is required to recognize a proportional share of Millennium’s OCI. Millennium is amortizing the unrealized loss related to these terminated interest rate swaps into earnings using the effective interest method through interest expense as interest payments are made. NiSource records its proportionate share of the amortization as Equity Earnings in Unconsolidated Affiliates at the Condensed Statements of Consolidated Income (unaudited). NiSource’s proportionate share of the remaining unrealized loss, net of tax, was $20.4 million as of September 30, 2011 and $21.1 million as of December 31, 2010, which are included in unrealized losses on cash flow hedges above.

Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The NiSource Chief Executive Officer is the chief operating decision maker.

At September 30, 2011, NiSource’s operations are divided into three primary business segments. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Gas Transmission and Storage Operations segment offers gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The following table provides information about business segments. NiSource uses operating income as its primary measurement for each of the reported segments and makes decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The following table provides additional information regarding NiSource’s Condensed Statements of Consolidated Cash Flows (unaudited) for the nine months ended September 30, 2011 and 2010:

The Management’s Discussion and Analysis, including statements regarding market risk sensitive instruments, contains “forward-looking statements,” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning NiSource’s plans, objectives, expected performance, expenditures and recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. From time to time, NiSource may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of NiSource, are also expressly qualified by these cautionary statements. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially.

Realization of NiSource’s objectives and expected performance is subject to a wide range of risks and can be adversely affected by, among other things, weather, fluctuations in supply and demand for energy commodities, growth opportunities for NiSource’s businesses, increased competition in deregulated energy markets, the success of regulatory and commercial initiatives, dealings with third parties over whom NiSource has no control, actual operating experience of NiSource’s assets, the regulatory process, regulatory and legislative changes, the impact of potential new environmental laws or regulations, the results of material litigation, changes in pension funding requirements, changes in general economic, capital and commodity market conditions, counterparty credit risk, and the matters set forth in the “Risk Factors” section of NiSource’s 2010 Form 10-K, which many of are beyond the control of NiSource. In addition, the relative contributions to profitability by each segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time. NiSource expressly disclaims a duty to update any of the forward-looking statements contained in this report.

The following Management’s Discussion and Analysis should be read in conjunction with NiSource’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

NiSource is an energy holding company under the Public Utility Holding Company Act of 2005 whose subsidiaries are engaged in the transmission, storage and distribution of natural gas in the high-demand energy corridor stretching from the Gulf Coast through the Midwest to New England and the generation, transmission and distribution of electricity in Indiana. NiSource generates virtually 100% of its operating income through these rate-regulated businesses. A significant portion of NiSource’s operations are subject to seasonal fluctuations in sales. During the heating season, which is primarily from November through March, net revenues from gas sales are more significant, and during the cooling season, which is primarily from June through September, net revenues from electric sales and transportation services are more significant than in other months.

For the nine months ended September 30, 2011, NiSource reported income from continuing operations of $280.6 million, or $1.00 per basic share, compared to $258.8 million, or $0.93 per basic share reported for the same period in 2010.

The increase in income from continuing operations was due primarily to the following items:

These factors and other impacts to the financial results are discussed in more detail within the following discussions of “Results of Operations” and “Results and Discussion of Segment Operations.”

NiSource’s business plan will continue to center on commercial and regulatory initiatives; commercial growth and expansion of the gas transmission and storage business; and financial management of the balance sheet.

NiSource is moving forward on regulatory initiatives across several distribution company markets. Whether through full rate case filings or other approaches, NiSource’s goal is to develop strategies that benefit all stakeholders as it addresses changing customer conservation patterns, develops more contemporary pricing structures, and embarks on long-term investment programs to enhance its infrastructure.

Northern Indiana’s electric business continues to advance a broad business agenda designed to deliver exceptional customer service, enhance operational and environmental performance, and establish a robust platform for ongoing earnings growth.

NiSource’s Gas Distribution Operations continues to execute its strategy of combining long-term infrastructure replacement and customer programs with complementary regulatory initiatives.

Refer to Note 7, “Regulatory Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for a complete discussion of regulatory and commercial matters.

NiSource’s Gas Transmission & Storage Operations continues to make progress on key strategies to enhance system reliability, develop new growth projects, and leverage the company’s strategic footprint in emerging shale gas production areas.

At the end of the third quarter, NiSource maintained approximately $462 million in net available liquidity. The company is actively evaluating a number of financing options that could be executed as early as the fourth quarter of 2011.

NiSource has had a long-term commitment to providing accurate and complete financial reporting as well as high standards for ethical behavior by its employees. NiSource’s senior management takes an active role in the development of this Form 10-Q and the monitoring of the company’s internal control structure and performance. In addition, NiSource will continue its mandatory ethics training program for all employees.

NiSource reported net income of $34.7 million, or $0.12 per basic share, for the three months ended September 30, 2011, compared to a net income of $33.2 million, or $0.12 per basic share, for the third quarter of 2010. Income from continuing operations was $36.3 million, or $0.13 per basic share, for the three months ended September 30, 2011, compared to income from continuing operations of $33.4 million, or $0.12 per basic share, for the third quarter of 2010. Operating income was $147.5 million, an increase of $24.2 million from the same period in 2010. All per share amounts are basic earnings per share. Basic average shares of common stock outstanding at September 30, 2011 were 280.8 million compared to 278.1 million at September 30, 2010.

Comparability of line item operating results between quarterly periods is impacted by regulatory and tax trackers that allow for the recovery in rates of certain costs such as bad debt expenses. Therefore, increases in these tracked operating expenses are offset by increases in net revenues and have essentially no impact on income from continuing operations.

Total consolidated net revenues (gross revenues less cost of sales) for the quarter ended September 30, 2011, were $745.6 million, a $27.5 million increase from the same period last year. This increase in net revenues was primarily due to increased Gas Distribution Operations’ net revenues of $17.7 million and increased Gas Transmission and Storage Operations’ net revenues of $16.0 million. This was partially offset by a decrease in Electric Operations’ net revenues of $6.8 million.

Operating expenses for the third quarter 2011 were $601.6 million, an increase of $3.3 million from the 2010 period. This increase was primarily due to higher environmental costs of $9.8 million and the current period effects of a $6.0 million environmental reserve adjustment in the prior period. Additionally, there was an increase in employee and administrative costs of $4.7 million predominantly as a result of an increased headcount. These increases were partially offset by decreased depreciation costs of $18.2 million primarily due to new approved depreciation rates at Northern Indiana within the Gas Distributions Operations’ segment.

Equity Earnings in Unconsolidated Affiliates were $3.5 million in both the third quarter of 2011 and 2010. Equity Earnings in Unconsolidated Affiliates includes investments in Millennium and Hardy Storage which are integral to the Gas Transmission and Storage Operations’ business. Equity earnings remained flat due to lower hedge ineffectiveness charges at Millennium, which was offset by higher interest costs associated with the August 2010 debt refinancing at Millennium.

Other Income (Deductions) reduced income by $94.1 million in 2011 compared to a reduction in income of $95.5 million in the prior year. The decrease in deductions is primarily due to lower interest expense of $1.9 million due to the $681.8 million November 2010 long-term debt maturity and the December 2010 tender offer repurchase of long-term debt of $273.1 million. The benefits were partially offset by incremental interest expense associated with the issuance of long-term debt of $400.0 million in June 2011 and $250.0 million in December 2010, reduced savings associated with interest rate swaps and higher average short-term borrowings and rates. Other-net income of $1.6 million was recorded in 2011 compared to $2.1 million in 2010.

Income tax expense for the third quarter of 2011 was $17.1 million compared to a benefit of $5.6 million in the prior year. The effective tax rates for the three months ended September 30, 2011 and 2010 were 32.0% and (20.1)%, respectively. The effective tax rate differs from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences such as the electric production tax deduction provided under Internal Revenue Code Section 199.

Refer to Note 12, “Income Taxes,” in the Notes to the Condensed Consolidated Financial Statements (unaudited) for more detail about income taxes.

There was a net loss of $1.6 million in the third quarter of 2011 from discontinued operations compared to a net loss of $0.2 million in the third quarter of 2010.

NiSource reported net income of $278.8 million, or $0.99 per basic share, for the nine months ended September 30, 2011, compared to net income of $258.6 million, or $0.93 per basic share, for the first nine months of 2010. Income from continuing operations was $280.6 million, or $1.00 per basic share, for the first nine months ended September 30, 2011, compared to income from continuing operations of $258.8 million, or $0.93 per basic share, for the comparable 2010 period. Operating income was $710.0 million, an increase of $44.1 million from the same period in 2010. All per share amounts are basic earnings per share. Basic average shares of common stock outstanding at September 30, 2011 were 280.1 million compared to 277.5 million at September 30, 2010.

Comparability of line item operating results between quarterly periods was impacted by regulatory and tax trackers that allow for the recovery in rates of certain costs such as bad debt expenses. Therefore, increases in these tracked operating expenses are offset by increases in net revenues and had essentially no impact on income from continuing operations.

Total consolidated net revenues (gross revenues less cost of sales) for the nine months ended September 30, 2011, were $2,572.7 million, a $50.2 million increase from the same period last year. This increase in net revenues was primarily due to increased Gas Transmission and Storage Operations’ net revenues of $31.0 million, increased Gas Distribution Operations’ net revenues of $9.9 million and increased Electric Operations’ net revenues of $8.3 million.

Operating expenses for the nine months ended September 30, 2011 were $1,871.5 million, an increase of $3.6 million from the 2010 period. This increase was primarily due to higher employee and administrative costs of $35.8 million predominantly as a result of an increased headcount, an increase in environmental costs of $12.1 million and higher electric generation costs of $10.0 million due to more outage weeks in the current period. Additionally, there was an increase in outside service costs of $9.1 million. These increases were partially offset by decreased depreciation costs of $46.2 million new approved depreciation rates at Northern Indiana within the Gas Distributions Operations’ segment and lower regulatory and tax trackers, which are offset in revenue, of $17.4 million.

Equity Earnings in Unconsolidated Affiliates were $8.8 million for the nine months ended September 30, 2011, a decrease of $2.5 million compared to 2010. Equity Earnings in Unconsolidated Affiliates includes investments in Millennium and Hardy Storage which are integral to the Gas Transmission and Storage Operations’ business. Equity earnings decreased primarily resulting from Millennium incurring higher interest costs associated with the August 2010 debt refinancing partially offset by lower hedge ineffectiveness charges at Millennium.

Other Income (Deductions) reduced income by $274.4 million for the nine months ended September 30, 2011 compared to a reduction in income of $287.5 million in the prior year. The decrease in deductions is primarily due to lower interest expense of $14.9 million due to the $681.8 million November 2010 long-term debt maturity and the December 2010 tender offer repurchase of long-term debt of $273.1 million. The benefits were partially offset by incremental interest expense associated with the issuance of long-term debt of $400.0 million in June of 2011 and $250.0 million in December 2010, reduced savings associated with interest rate swaps and higher average short-term borrowings and rates. Other-net income of $5.5 million was recorded in 2011 compared to $7.3 million in 2010.

Income taxes for the first nine months of 2011 were $155.0 million, an increase of $35.4 million compared to the first nine months of 2010, mainly attributable to higher pre-tax income.

The effective tax rates for the nine months ended September 30, 2011 and 2010 were 35.6% and 31.6%, respectively. These effective tax rates differ from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences such as the electric production tax deduction provided under Internal Revenue Code Section 199.

and distribution assets in 2008. At December 31, 2010, NiSource had $107.4 million of unrecorded tax benefits related to this method change pending resolution on audit or further guidance from the IRS or United States Treasury Department. As a result of the issuance of the revenue procedure NiSource revised its estimates and recorded tax benefits of $12.9 million in the third quarter of 2011. Excluding minor amounts of interest, the revision of estimate did not impact total income tax expense.

Refer to Note 12, “Income Taxes,” in the Notes to the Condensed Consolidated Financial Statements (unaudited) for more detail about income taxes.

There was a $1.8 million net loss from discontinued operations for the nine months ended September 30, 2011, compared to a $0.2 million net loss from discontinued operations in 2010.

A significant portion of NiSource’s operations, most notably in the gas distribution, gas transportation and storage and electric distribution businesses, are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows from the electric business during the summer cooling season and external short-term and long-term financing, is used to purchase gas to place in storage for heating season deliveries and perform necessary maintenance of facilities. NiSource believes that through income generated from operating activities, amounts available under its revolving credit facility, commercial paper program, long-term debt agreements and NiSource’s ability to access the capital markets, there is adequate capital available to fund its operating activities and capital expenditures in 2011.

Net cash from operating activities for the nine months ended September 30, 2011 was $794.1 million, an increase of $461.6 million compared to the nine months ended September 30, 2010. Gas price fluctuations and the related approved rates for recovery significantly impacted working capital when comparing the two periods. During 2011, under-collected gas costs from 2010 were received from customers providing a source of working capital. Conversely, during the comparable period in 2010 over-collected gas costs from 2009 were returned to the customers resulting in a use of working capital.

Pension and Other Postretirement Plan Funding. For the nine months ended September 30, 2011, NiSource has contributed $142.7 million to its pension plans and $41.4 million to its other postretirement benefit plans. NiSource is considering significant contributions to the pension plans in 2011 but such additional contributions are dependent on market conditions and other factors.

NiSource’s capital expenditures for the nine months ended September 30, 2011 were $774.2 million, compared to $553.7 million for the comparable period in 2010. The increase is the result of increased spending for the Gas Distribution Operations’ infrastructure replacement programs and Electric Operations’ system growth. NiSource projects 2011 capital expenditures to be approximately $1.1 billion.

Restricted cash was $180.1 million and $202.9 million as of September 30, 2011 and December 31, 2010, respectively. The decrease in restricted cash was due to a change in investment positions within NiSource’s risk management and energy marketing activities, partially offset by a decrease in forward gas prices which resulted in increased net margin deposits on open derivative contracts.

Long-term Debt. Refer to Note 15, “Long-Term Debt,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on long-term debt.

Credit Facilities. On March 3, 2011, NiSource Finance entered into a new $1.5 billion four-year revolving credit facility with a syndicate of banks led by Barclays Capital. The new facility replaced an existing $1.5 billion five-year credit facility which would have expired during July 2011. The purpose of the new facility is to fund ongoing working capital requirements and for general corporate purposes, including supporting liquidity for the company’s commercial paper program, and provides for the issuance of letters of credit.

NiSource Finance had $615.0 million in outstanding borrowings under its four-year revolving credit facility at September 30, 2011, at a weighted average interest rate of 1.96%. Under its previous revolving credit facility, NiSource Finance had borrowings of $1,107.5 million at December 31, 2010, at a weighted average interest rate of 0.78%. In addition, NiSource Finance had $425.8 million in commercial paper outstanding at September 30, 2011, at a weighted average interest rate of 0.98%.

As of September 30, 2011 and December 31, 2010, NiSource had $193.2 million and $275.0 million, respectively, of short-term borrowings recorded on the Condensed Consolidated Balance Sheets (unaudited) and cash from financing activities in the same amount relating to its accounts receivable securitization facilities. See Note 10, “Transfers of Financial Assets.”

As of September 30, 2011 and December 31, 2010, NiSource had $37.4 million and $32.5 million, respectively, of stand-by letters of credit outstanding of which $19.2 million and $14.2 million, respectively, were under the revolving credit facility.

As of September 30, 2011, an aggregate of $440.0 million of credit was available under the credit facility.

Sale of Trade Accounts Receivables. Refer to Note 10, “Transfers of Financial Assets,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on the sale of accounts receivable.

All accounts receivable sold to the commercial paper conduits are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables sold is determined, in part, by required loss reserves under the agreements.

Credit Ratings. On February 24, 2011, Standard & Poor’s affirmed the senior unsecured ratings for NiSource and its subsidiaries at BBB-. Standard & Poor’s outlook for NiSource and all of its subsidiaries is stable. On December 14, 2010, Fitch affirmed the senior unsecured ratings for NiSource at BBB-, and the existing ratings of all other subsidiaries. Fitch’s outlook for NiSource and all of its subsidiaries is stable. On November 19, 2010, Moody’s Investors Service affirmed the senior unsecured ratings for NiSource at Baa3, and the existing ratings of all other subsidiaries. Moody’s outlook for NiSource and all of its subsidiaries is stable. Although all ratings continue to be investment grade, a downgrade by Standard & Poor’s, Moody’s or Fitch would result in a rating that is below investment grade. NiSource is scheduled for their annual credit reviews with all three rating agencies in November 2011.

Certain NiSource affiliates have agreements that contain “ratings triggers” that require increased collateral if the credit ratings of NiSource or certain of its subsidiaries are rated below BBB- by Standard & Poor’s or Baa3 by Moody’s. The additional collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $20.8 million. In addition to agreements with ratings triggers, there are other agreements that contain “adequate assurance” or “material adverse change” provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business. In addition, under Northern Indiana’s trade receivables sales program, an event of termination occurs if Northern Indiana’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB or Ba2 at either Standard & Poor’s or Moody’s, respectively. Likewise, under Columbia of Ohio’s and Columbia of Pennsylvania’s trade receivables sales programs, an event of termination occurs if NiSource’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB- or Ba3 at either Standard & Poor’s or Moody’s, respectively.

Contractual Obligations. Refer to Note 12, “Income Taxes,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for material changes recorded during the nine months ended September 30, 2011 to NiSource’s uncertain tax positions recorded as of December 31, 2010.

Forward Equity Sale. Refer to Note 4, “Forward Equity Agreement,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on financing activities related to the forward equity sale.

Risk is an inherent part of NiSource’s energy businesses. The extent to which NiSource properly and effectively identifies, assesses, monitors and manages each of the various types of risk involved in its businesses is critical to its profitability. NiSource seeks to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal market risks that are involved in NiSource’s energy businesses: commodity price risk, interest rate risk and credit risk. Risk management at NiSource is a multi-faceted process with oversight by the Risk Management Committee that requires constant communication, judgment and knowledge of specialized products and markets. NiSource’s senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These include but are not limited to market, operational, financial and strategic risk types. In recognition of the increasingly varied and complex nature of the energy business, NiSource’s risk management process, policies and procedures continue to evolve and are subject to ongoing review and modification.

Various analytical techniques are employed to measure and monitor NiSource’s market and credit risks, including VaR. VaR represents the potential loss or gain for an instrument or portfolio from changes in market factors, for a specified time period and at a specified confidence level.

NiSource is exposed to commodity price risk as a result of its subsidiaries’ operations involving natural gas and power. To manage this market risk, NiSource’s subsidiaries use derivatives, including commodity futures contracts, swaps and options. NiSource is not involved in speculative energy trading activity.

Commodity price risk resulting from derivative activities at NiSource’s rate-regulated subsidiaries is limited, since regulations allow recovery of prudently incurred purchased power, fuel and gas costs through the rate-making process, including gains or losses on these derivative instruments. If states should explore additional regulatory reform, these subsidiaries may begin providing services without the benefit of the traditional rate-making process and may be more exposed to commodity price risk. Some of NiSource’s rate-regulated utility subsidiaries offer commodity price risk products to its customers for which derivatives are used to hedge forecasted customer usage under such products. These subsidiaries do not have regulatory recovery orders for these products and are subject to gains and losses recognized in earnings due to hedge ineffectiveness.

NiSource is exposed to interest rate risk as a result of changes in interest rates on borrowings under its revolving credit agreement, commercial paper program and accounts receivable programs, which have interest rates that are indexed to short-term market interest rates. NiSource is also exposed to interest rate risk due to changes in interest rates on fixed-to-variable interest rate swaps that hedge the fair value of long-term debt. Based upon average borrowings and debt obligations subject to fluctuations in short-term market interest rates, an increase (or decrease) in short-term interest rates of 100 basis points (1%) would have increased (or decreased) interest expense by $3.9 million and $12.2 million for the three and nine months ended September 30, 2011, respectively, and $3.6 million and $10.3 million for the three and nine months ended September 30, 2010, respectively.

Due to the nature of the industry, credit risk is embedded in many of NiSource’s business activities. NiSource’s extension of credit is governed by a Corporate Credit Risk Policy. In addition, Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by the Corporate Credit Risk function which is independent of commercial operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. For derivative related contracts, credit risk arises when counterparties are obligated to deliver or purchase defined commodity units of gas or power to NiSource at a future date per execution of contractual terms and conditions. Exposure to credit risk is measured in terms of both current obligations and the market value of forward positions net of any posted collateral such as cash, letters of credit and qualified guarantees of support.

NiSource closely monitors the financial status of its banking credit providers and interest rate swap counterparties. NiSource evaluates the financial status of its banking partners through the use of market-based metrics such as credit default swap pricing levels, and also through traditional credit ratings provided by major credit rating agencies.

NiSource measures certain financial assets and liabilities at fair value. The level of the fair value hierarchy disclosed is based on the lowest level of input that is significant to the fair value measurement. NiSource’s financial assets and liabilities include price risk assets and liabilities, available-for-sale securities and a deferred compensation plan obligation.

Exchange-traded derivative contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore nonperformance risk has not been incorporated into these valuations. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. NiSource uses a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, i.e., inputs derived principally from or corroborated by observable market data by correlation or other means. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures.

Price risk management assets also include fixed-to-floating interest-rate swaps, which are designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. NiSource uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, as well as market parameters such as current and projected interest rates and volatility. As they are based on observable data and valuations of similar instruments, the interest-rate swaps are categorized in Level 2 in the fair value hierarchy. Credit risk is considered in the fair value calculation of the interest rate swap.

Refer to Note 9, “Fair Value Disclosures,” in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information on NiSource’s fair value measurements.

Market risk refers to the risk that a change in the level of one or more market prices, rates, indices, volatilities, correlations or other market factors, such as liquidity, will result in losses for a specified position or portfolio. NiSource calculates a one-day VaR at a 95% confidence level for the unregulated gas marketing group that utilizes a variance/covariance methodology. The daily market exposure for the unregulated gas marketing portfolio on an average, high and low basis was $0.1 million, $0.1 million and $0.1 million for the third quarter of 2011, respectively. The daily market exposure for the unregulated gas marketing portfolio for the nine months ended September 30, 2011 on an average, high and low basis was $0.1 million, $0.1 million and zero, respectively. Prospectively, management has set the VaR limit at $0.8 million for gas marketing. Exceeding this limit would result in management actions to reduce portfolio risk.

Refer to Note 8, “Risk Management Activities,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for further discussion of NiSource’s risk management.

As a part of normal business, NiSource and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit.

NiSource has issued guarantees that support up to approximately $149.9 million of commodity-related payments for its current and former subsidiaries involved in energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions involving natural gas and electricity. To the extent liabilities exist under the commodity-related contracts subject to these guarantees, such liabilities are included in the Condensed Consolidated Balance Sheets (unaudited).

NiSource has purchase and sales agreement guarantees totaling $30.0 million, which guarantee performance of the seller’s covenants, agreements, obligations, liabilities, representations and warranties under the agreements. No amounts related to the purchase and sales agreement guarantees are reflected in the Condensed Consolidated Balance Sheets (unaudited). Management believes that the likelihood NiSource would be required to perform or otherwise incur any significant losses associated with any of the aforementioned guarantees is remote.

NiSource has other guarantees outstanding. Refer to Note 18-A, “Guarantees and Indemnities,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information about NiSource’s off balance sheet arrangements.

Goodwill. NiSource’s goodwill assets at September 30, 2011 were $3,677.3 million, most of which resulted from the acquisition of Columbia on November 1, 2000. In addition, Northern Indiana Gas Distribution Operations’ goodwill assets at June 30, 2011 related to the purchase of Northern Indiana Fuel and Light and Kokomo Gas were $18.8 million. As required, NiSource tests for impairment of goodwill on an annual basis and on an interim basis when events or circumstances indicate that a potential impairment may exist. NiSource’s annual goodwill test takes place in the second quarter of each year and was most recently finalized as of June 30, 2011. The fair value of each reporting unit exceeded the carrying value based on this impairment test. Refer to Note 11, “Goodwill Assets,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information concerning NiSource’s annual goodwill test.

There were no other significant changes to critical accounting policies for the period ended September 30, 2011.

Refer to Note 2, “Recent Accounting Pronouncements,” in the Notes to Condensed Consolidated Financial Statements (unaudited).

In February 2010, the SEC expressed its commitment to the development of a single set of high quality globally accepted accounting standards and directed its staff to execute a work plan addressing specific areas of concern regarding the potential incorporation of IFRS for the U.S. In October 2010, the SEC staff issued its first public progress report on the work plan and in May 2011, a Staff Paper was issued outlining a possible endorsement approach for incorporation of IFRS into the U.S. financial reporting system, if the SEC were to decide that incorporation of IFRS is in the best interest of U.S. investors. Under this possible framework, IFRS would be incorporated into GAAP during a transition period (e.g., five to seven years) and the FASB would be retained as the US standard setter. The SEC is expected to vote by the end of 2011 on whether to require the use of IFRS and by what method. Additionally, in December 2010 the SEC chairman publicly stated that companies would be allowed a minimum of four years to adjust if the use of IFRS is mandated.

In the fourth quarter of 2010, NiSource completed a comprehensive assessment of IFRS to understand the key accounting and reporting differences compared to U.S. GAAP and to assess the potential organizational, process and system impacts that would be required. The accounting differences between U.S. GAAP and IFRS are complex and significant in many aspects, and conversion to IFRS would have broad impacts across NiSource. In addition to financial statement and disclosure changes, converting to IFRS would involve changes to processes and controls, regulatory and management reporting, financial reporting systems, and other areas of the organization. As a part of the IFRS assessment project, a preliminary conversion roadmap was created for reporting IFRS. This IFRS conversion roadmap, and NiSource’s strategy for addressing a potential mandate of IFRS, will be re-assessed when the SEC makes its determination on whether to require the use of IFRS and by what method.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was passed by Congress on July 15, 2010 and was signed into law on July 21, 2010. The Act, among other things, establishes a Financial Stability Oversight Council (FSOC) and a Consumer Financial Protection Bureau (CFPB) whose duties will include the monitoring of domestic and international financial regulatory proposals and developments, as well as the protection of consumers. The FSOC may submit comments to the SEC and any standard-setting body with respect to an existing or proposed accounting principle, standard or procedure. The Act also creates increased oversight of the over-the-counter derivative market, requiring certain OTC transactions to be cleared through a clearing house and requiring cash margins to be posted for those transactions. Many regulations will be issued to implement the Act over the next twelve to twenty four months. NiSource is currently reviewing the Act and is unable to determine the final impact that the Act will have on its operations until these regulations have been issued.

NiSource’s operations are divided into three primary business segments: Gas Distribution Operations, Gas Transmission and Storage Operations, and Electric Operations.

NiSource’s natural gas distribution operations serve approximately 3.3 million customers in seven states: Ohio, Indiana, Pennsylvania, Massachusetts, Virginia, Kentucky and Maryland. The regulated subsidiaries offer both traditional bundled services as well as transportation only for customers that purchase gas from alternative suppliers. The operating results reflect the temperature-sensitive nature of customer demand with 74% of annual residential and commercial throughput affected by seasonality. As a result, segment operating income is higher in the first and fourth quarters reflecting the heating demand during the winter season.

Refer to Note 7, “Regulatory Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on significant rate developments and cost recovery and trackers for the Gas Distribution Operations segment.

Customer Usage. The NiSource distribution companies have experienced declining usage by customers, due in large part to the sensitivity of sales to volatility in commodity prices. A significant portion of the LDCs’ operating costs are fixed in nature. Historically, rate design at the distribution level has been structured such that a large portion of cost recovery is based upon throughput, rather than in a fixed charge. In addition, increased efficiency of natural gas appliances has caused a decline in average use per customer. Columbia of Ohio restructured its rate design through a base rate proceeding and has adopted a “de-coupled” rate design which more closely links the recovery of fixed costs with fixed charges. In regulatory proceedings in 2009, Columbia of Massachusetts and Columbia of Virginia received approval of decoupling mechanisms which adjust revenues to an approved benchmark level through a volumetric adjustment factor. Each of the states in which the NiSource LDCs operate has different requirements regarding the procedure for establishing such charges. In its 2010 rate case, Northern Indiana implemented a higher fixed customer charge for residential and small customer classes moving toward full straight fixed variable rate design. This rate design was also incorporated in the settlement of the 2011 merger of the three Indiana LDCs.

Various environmental matters occasionally impact the Gas Distribution Operations segment. As of September 30, 2011, a reserve has been recorded to cover probable and estimable environmental response actions. Refer to Note 18-C, “Environmental Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding environmental matters for the Gas Distribution Operations segment.

In general, NiSource calculates the weather related revenue variance based on changing customer demand driven by weather variance from normal heating degree-days. Normal is evaluated using heating degree days across the NiSource distribution region. While the temperature base for measuring heating degree-days (i.e. the estimated average daily temperature at which heating load begins) varies slightly across the region, the NiSource composite measurement is based on 65 degrees. NiSource composite heating degree-days reported do not directly correlate to the weather related dollar impact on the results of Gas Distribution Operations. Heating degree-days experienced during different times of the year or in different operating locations may have more or less impact on volume and dollars depending on when and where they occur. When the detailed results are combined for reporting, there may be weather related dollar impacts on operations when there is not an apparent or significant change in the aggregated NiSource composite heating degree-day comparison.

Weather in the Gas Distribution Operations’ territories for the third quarter of 2011 was 27% colder than normal and 56% colder than the third quarter in 2010.

Weather in the Gas Distribution Operations’ territories for the nine months ended September 30, 2011 was 3% colder than normal and 10% colder compared to the same period in 2010.

Total volumes sold and transported of 148.3 MMDth for the third quarter of 2011 increased by 2.1 MMDth from the same period last year. This 1.4% increase in volume was primarily due to higher industrial usage and colder weather.

Total volumes sold and transported of 678.8 MMDth for the first nine months of 2011 increased by 51.6 MMDth from the same period last year. This 8.2% increase in volume was primarily due to higher industrial usage and colder weather.

Net revenues for the third quarter of 2011 were $259.5 million, an increase of $17.7 million from the same period in 2010, primarily due to the impact of increased residential and commercial margins of $15.4 million as a result of Northern Indiana’s change from a volumetric-based rate design to one with a higher fixed charge. The new rate design provides a greater proportion of recovery through the monthly fixed customer charge as opposed to the volumetric charge for certain customer classes. The revenue variance experienced in the third quarter from Northern Indiana’s rate design change will be offset during the periods of higher usage throughout the year. Additionally, there was an increase of $7.2 million for other regulatory and service programs, including impacts from the implementation of rates under Columbia of Ohio’s approved infrastructure replacement program and rate cases at other NiSource utilities. The increase in net revenues was partially offset by a decrease in net regulatory and tax trackers of $7.9 million, which are offset in expense.

At Northern Indiana, customer billings and related gross sales revenues are adjusted for amounts related to under and over-recovered purchased gas costs from prior periods per regulatory order. These amounts are primarily reflected in the “Other” gross revenues statistic provided at the beginning of this segment discussion. The adjustment to Other gross revenues for the three and nine months ended September 30, 2011 was a revenue increase of $3.8 million and a decrease of $45.9 million, respectively, compared to an increase of $0.9 million and $114.8 million for the three and nine months ended September 30, 2010, respectively.

Net revenues for the nine months ended September 30, 2011 were $1,160.1 million, an increase of $9.9 million from the same period in 2010, due primarily to an increase of $21.6 million for other regulatory and service programs, including impacts from rate cases at other NiSource utilities and the implementation of new rates under Columbia of Ohio’s approved infrastructure replacement program. Additionally, there were increases of approximately $14.4 million due to the impact of colder weather and $10.6 million in residential and commercial margins due primarily to Northern Indiana’s change from a volumetric-based rate design to one with a higher fixed charge. The new rate design provides a greater proportion of recovery through the monthly fixed customer charge as opposed to the volumetric charge for certain customer classes. The revenue variance experienced from Northern Indiana’s rate design change will be offset in periods of higher usage. Net revenues also increased $5.7 million as the result of a contract reserve that was established in 2010, $2.8 million from Bear Garden Station which was placed into service in July of 2010, and $2.5 million related to a reserve for unaccounted for gas recorded in 2010. The increases in net revenues were partially offset by a decrease in net regulatory and tax trackers of $26.5 million, which are offset in expense, lower off-system sales of $18.8 million primarily as a result of the standard service offer auction at Columbia of Ohio in the second quarter of 2010, and a decrease in industrial margins of $6.6 million.

For the third quarter of 2011, Gas Distribution Operations reported operating income of $7.9 million, an increase of $50.4 million from the comparable 2010 period. Operating income increased as a result of lower operating expenses and higher net revenues, as described above. Operating expenses were $32.7 million lower than the comparable period reflecting a decrease of $20.1 million in depreciation costs primarily due to new approved depreciation rates at Northern Indiana and $7.5 million as a result of regulatory trackers, which are offset in net revenue. Additionally, there was a $3.0 million decrease in employee and administrative costs and lower uncollectible accounts of $1.5 million. These decreases were partially offset by an increase in outside service costs of $3.0 million.

For the nine months ended September 30, 2011, Gas Distribution Operations reported operating income of $295.9 million, an increase of $84.8 million from the comparable 2010 period. The increase in operating income was primarily attributable to lower operating expenses and higher net revenues described above. Operating expenses decreased $74.9 million as a result of a decrease of $59.5 million in depreciation costs primarily due to new approved depreciation rates at Northern Indiana and $34.1 million as a result of lower regulatory trackers, which are offset in net revenue. Additionally, there was a decrease in uncollectible costs of $7.4 million. These decreases were partially offset by an increase in employee and administrative costs of $14.2 million, an increase in other taxes, including trackers offset in net revenue, of $10.3 million, and higher outside service costs of $5.7 million.

NiSource’s Gas Transmission and Storage Operations segment primarily consists of the operations of Columbia Transmission, Columbia Gulf, NiSource Midstream, Crossroads Pipeline, and the equity investments in Millennium and Hardy Storage. In total, NiSource owns a pipeline network of approximately 15,000 miles extending from the Gulf of Mexico to New York and the eastern seaboard. The pipeline network serves customers in 16 northeastern, mid-Atlantic, midwestern and southern states, as well as the District of Columbia. In addition, the Gas Transmission and Storage Operations segment operates one of the nation’s largest underground natural gas storage systems.

Gas Transmission and Storage Operations’ most significant projects are as follows:

Majorsville, PA. The Gas Transmission and Storage Operations segment executed three separate projects totaling approximately $80 million in the Majorsville, PA vicinity to aggregate Marcellus Shale gas production for downstream transmission. Fully contracted, the pipeline and compression assets allow the Gas Transmission and Storage Operations segment to gather and deliver more than 325,000 Dth per day of Marcellus production gas to the Majorsville MarkWest Liberty processing plants developed by MarkWest Liberty Midstream & Resources L.L.C.

In 2010, Columbia Transmission received approval from the FERC to refunctionalize certain transmission assets to gathering and transferred these pipeline facilities to a newly formed affiliate, NiSource Midstream Services, LLC. These facilities are included in providing non-FERC jurisdiction gathering services to producers in the Majorsville, PA vicinity. Two of the three projects were completed and placed into service on August 1, 2010, creating an integrated gathering and processing system serving Marcellus production in southwestern Pennsylvania and northern West Virginia. Precedent agreements were executed by anchor shippers in the fourth quarter of 2009, which were superseded by the execution of long-term service agreements in August and September 2010. In the fourth quarter of 2010, construction began on the third project on a pipeline to deliver residue gas from the Majorsville MarkWest Liberty processing plant to the Texas Eastern Wind Ridge compressor station in southwestern Pennsylvania to provide significant additional capacity to eastern markets. This third project was placed into service in April 2011.

Power Plant Generation Project. The Gas Transmission and Storage Operations segment is moving forward with this nearly $35 million expansion project, which includes new pipeline and modifications to existing compression assets, with Virginia Power Services Energy Corporation, Inc., the energy manager for Virginia Electric Power Company. This project will expand the Columbia Transmission system in order to provide up to nearly 250,000 Dth per day of transportation capacity under a long-term, firm contract. The project is expected to be ready for commercial operations by mid-2014.

Clendenin, West Virginia. Construction began on this approximately $18 million capital project in 2010 to modify existing facilities in the Clendenin, West Virginia area to move Marcellus production to liquid market centers. The Clendenin project provides Columbia Transmission the ability to meet incremental transportation demand of up to 150,000 Dth per day. Long-term firm transportation contracts for 130,000 Dth per day have been executed, some of which began in the third quarter 2010 and others that began in June 2011.

Smithfield. The Gas Transmission and Storage Operations segment made approximately $14 million of capital investments for modifications to existing pipeline and compressor facilities to accommodate receipt of up to 150,000 Dth per day of additional Marcellus gas from connections near Smithfield, West Virginia and Waynesburg, Pennsylvania. Three anchor shippers agreed to long-term, firm transportation contracts, one contract that began in April 2011 and others that began in August 2011. The project is expected to be fully in service in the fourth quarter of 2011.

Line WB Expansion. The Gas Transmission and Storage Operations segment expanded its WB system through investment in additional facilities, which provide transportation service on a firm basis from Loudoun, Virginia to Leach, Kentucky. The expansion totaled approximately $14 million, allowing producers to meet incremental transportation demand in the Marcellus/Appalachian Basin. Binding precedent agreements for approximately 175,000 Dth per day of firm transportation capacity were executed, some which began in January 2011. Construction on all facilities was completed and placed into service in the third quarter of 2011.

East Lateral. In 2010, the Gas Transmission and Storage Operations segment initiated a $5 million project to modify existing facilities on the Columbia Gulf East Lateral to provide firm transportation services for up to 300,000 Dth per day. Firm transportation contracts for 250,000 Dth per day were executed for five-year terms. This FERC-approved project was completed and put into service in May 2011.

Southern Appalachian. The Gas Transmission and Storage Operations segment invested nearly $4 million to expand Line SM-116 to transport approximately 38,500 Dth per day on a firm basis as a continuation of its strategy to provide transportation services to producers of Marcellus and Appalachian gas. This additional capacity is supported by executed, binding precedent agreements. These additional facilities were placed in service in April 2011.

Rimersburg Expansion. The Gas Transmission and Storage Operations segment has approved an investment of $6 million for the first phase of this project that will ultimately add up to 200,000 Dth per day of capacity to north central Pennsylvania to meet the growing demands of producers in the area. The first phase of the project will consist of the expansion of Line 134 from the Brinker compressor station to the Iowa regulator. This will add approximately 19,000 Dth per day of additional capacity, all of which has been sold through precedent agreements. The second phase of this project is still under commercial development and will require management approval. The project’s first phase is currently scheduled to go into service in the first quarter of 2012.

Millennium Pipeline. Millennium Pipeline Company, L.L.C. operates approximately 250 miles of pipeline granted under the authority of the FERC. The Millennium pipeline has the capability to transport up to 525,400 Dth per day of natural gas to markets along its route, which lies between Corning, New York and Ramapo, New York, as well as to the New York City market through its pipeline interconnections. Columbia Transmission owns a 47.5% interest in Millennium and acts as operator for the pipeline in partnership with DTE Millennium Company and National Grid Millennium LLC, which each own an equal remaining share of the company.

Distributions of available accumulated earnings during the nine months ended September 30, 2011 were $15.0 million made to its partners, each sharing based upon their respective ownership percentages. Millennium returned $23.8 million of capital to Columbia Transmission during the same period in 2010. Columbia Transmission made no contributions during the nine months ended September 30, 2011 and $88.1 million during the same period in 2010.

Hardy Storage. Hardy Storage is a joint venture between subsidiaries of Columbia Transmission and Piedmont that manages an underground storage field in Hardy and Hampshire counties in West Virginia. Columbia Transmission serves as operator of the company, which is regulated by the FERC. Hardy Storage has a working storage capacity of 12 Bcf and the ability to deliver 176,000 Dth of natural gas per day.

Hardy Storage distributed $7.5 million and $15.8 million of available accumulated earnings during the nine months ended September 30, 2011 and 2010, respectively, to its partners, each sharing equally in the distribution. Columbia Transmission made no contributions during 2011 or 2010.

During the first quarter 2010, Hardy Storage converted its outstanding borrowings of $123.4 million, which were partially guaranteed by Columbia Transmission, under its temporary financing agreement to a secured permanent financing. As a result, Columbia Transmission was released from its underlying guarantee.

Columbia Transmission and Columbia Gulf compete for transportation customers based on the type of service a customer needs, operating flexibility, available capacity and price. Columbia Gulf and Columbia Transmission provide a significant portion of total transportation services under firm contracts and derive a smaller portion of revenues through interruptible contracts, with management seeking to maximize the portion of physical capacity sold under firm contracts.

Firm service contracts require pipeline capacity to be reserved for a given customer between certain receipt and delivery points. Firm customers generally pay a “capacity reservation” fee based on the amount of capacity being reserved regardless of whether the capacity is used, plus an incremental usage fee when the capacity is used. Annual capacity reservation revenues derived from firm service contracts generally remain constant over the life of the contract because the revenues are based upon capacity reserved and not whether the capacity is actually used. The high percentage of revenue derived from capacity reservation fees mitigates the risk of revenue fluctuations within the Gas Transmission and Storage Operations segment due to changes in near-term supply and demand conditions. For the quarter ended September 30, 2011, approximately 92.3% of the transportation revenues were derived from capacity reservation fees paid under firm contracts and 5.7% of the transportation revenues were derived from usage fees under firm contracts compared to approximately 91.1% and 7.6%, respectively, for the quarter ended September 30, 2010. For the nine months ended September 30, 2011, approximately 91.7% of the transportation revenues were derived from capacity reservation fees paid under firm contracts and 6.4% of the transportation revenues were derived from usage fees under firm contracts compared to approximately 91.5% and 4.8%, respectively, for the nine months ended September 30, 2010.

Interruptible transportation service is typically short term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay a usage fee only for the volume of gas actually transported. The ability to provide this service is limited to available capacity not otherwise used by firm customers, and customers receiving services under interruptible contracts are not assured capacity in the pipeline facilities. Gas Transmission and Storage Operations provides interruptible service at competitive prices in order to capture short term market opportunities as they occur and interruptible service is viewed by management as an important strategy to optimize revenues from the gas transmission assets. For the quarters ended September 30, 2011 and 2010, approximately 2.0% and 1.3%, respectively, of the transportation revenues were derived from interruptible contracts. For the nine months ended September 30, 2011 and 2010, approximately 1.9% and 3.7%, respectively, of the transportation revenues were derived from interruptible contracts.

Refer to Note 7, “Regulatory Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on regulatory matters for the Gas Transmission and Storage Operations segment.

Various environmental matters occasionally impact the Gas Transmission and Storage Operations segment. As of September 30, 2011, a reserve has been recorded to cover probable and estimable environmental response actions. Refer to Note 18-C, “Environmental Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding environmental matters for the Gas Transmission and Storage Operations segment.

Columbia Transmission’s throughput consists of city gate deliveries of transportation and storage services for LDCs and other customers within its market area, which covers portions of Northeastern, mid-Atlantic, Midwestern, and Southern states and the District of Columbia. Throughput for Columbia Gulf reflects mainline transportation services delivered to Leach, Kentucky and short-haul transportation services for gas delivered south of Leach, Kentucky. Crossroads Pipeline serves customers in Northern Indiana and Ohio. Intra-segment eliminations represent gas delivered to an affiliated pipeline within this segment.

Throughput for the Gas Transmission and Storage Operations segment totaled 334.7 MMDth for the third quarter of 2011, compared to 281.0 MMDth for the same period in 2010. The increase of 53.7 MMDth for the three-month period was attributable to increased transportation from the Marcellus, Haynesville and Barnett shale areas and increased deliveries to the power generation plants of the LDC’s due to the more advantageous pricing of gas compared to coal.

Throughput for the Gas Transmission and Storage Operations segment totaled 1,183.7 MMDth for the first nine months of 2011, compared to 972.1 MMDth for the same period in 2010. The increase of 211.6 MMDth was primarily due increased transportation from the Marcellus, Haynesville and Barnett shale areas and increased deliveries to the power generation plants of the LDC’s due to the more advantageous pricing of gas compared to coal. Additionally, there were increased deliveries to local utilities to satisfy heating demand during a colder than normal winter.

Net revenues were $233.5 million for the third quarter of 2011, an increase of $16.0 million from the same period in 2010, primarily due to higher demand margin revenue of $7.2 million as a result of growth projects placed into service since the third quarter of 2010. Additionally, there was an increase of $5.2 million in regulatory trackers, which are offset in expense, and an increase of $3.5 million due to the net impact of the rate case filing at Columbia Gulf.

Net revenues were $722.4 million for the first nine months of 2011, an increase of $31.0 million from the same period in 2010, primarily due to higher demand margin revenue of $21.1 million as a result of growth projects placed into service since the third quarter of 2010. Additionally, there was an increase of $9.2 million due to the net impact of the rate case filing at Columbia Gulf. Net revenues also increased due to higher regulatory trackers of $6.3 million, which are offset in expense, increased mineral rights royalty revenues of $5.6 million, higher condensate revenue of $4.4 million, increased commodity margin revenue of $3.6 million, and a one-time settlement of $2.8 million. These increases in net revenues were partially offset by the impact of $8.3 million related to the recognition in 2010 of revenue for a previously deferred gain for native gas contributed to Hardy Storage Company from Columbia Transmission following Hardy Storage securing permanent financing. Additionally, revenues decreased due to the impact of $5.4 million of fees received from a contract buy-out during the second quarter of 2010 and lower shorter term transportation and storage services of $5.2 million.

Operating income was $68.2 million for the third quarter of 2011, a decrease of $8.0 million from the third quarter of 2010. This decrease is due to higher operating expenses partially offset by higher net revenues, as described above. Operating expenses increased $24.0 million as a result of higher environmental costs of $11.2 million, increased regulatory trackers of $5.2 million, which are offset in revenue, increased employee and administrative costs of $5.1 million, and executive separation costs of $3.5 million.

Operating income was $271.4 million for the nine months ended September 30, 2011, a decrease of $5.6 million from the comparable period in 2010. Operating income decreased as a result of higher operating expenses and lower equity earnings partially offset by the increase in net revenues, as described above. Operating expenses increased $34.1 million primarily due to higher environmental costs of $13.2 million, an increase in employee and administrative costs of $9.9 million, higher regulatory trackers of $6.3 million, which are offset in net revenues, and higher depreciation costs of $3.2 million. Equity earnings decreased $2.5 million as a result of higher interest costs associated with the August 2010 debt refinancing at Millennium partially offset by lower hedge ineffectiveness charges at Millennium.

NiSource generates and distributes electricity, through its subsidiary Northern Indiana, to approximately 457 thousand customers in 20 counties in the northern part of Indiana. The operating results reflect the temperature-sensitive nature of customer demand with annual sales affected by temperatures in the northern part of Indiana. As a result, segment operating income is generally higher in the second and third quarters, reflecting cooling demand during the summer season.

On October 29, 2009, Northern Indiana filed its 2009 Integrated Resource Plan with the IURC. The plan evaluates demand-side and supply-side resource alternatives to reliably and cost-effectively meet Northern Indiana customers’ future energy requirements over the next twenty years. With the effects of the present economy, existing resources are projected to be sufficient through 2012 to serve customers’ needs. Therefore, Northern Indiana’s two requests for proposals to secure additional new sources of electric power issued on October 24, 2008 were not acted upon. With numerous variables contributing to uncertainty in the near-term outlook, Northern Indiana continues to monitor and assess economic, regulatory and legislative activity, and will update its resource plan in the fourth quarter of 2011.

Refer to Note 7, “Regulatory Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on significant rate developments, MISO, and cost recovery and trackers for the Electric Operations segment.

Various environmental matters occasionally impact the Electric Operations segment. As of September 30, 2011, a reserve has been recorded to cover probable and estimable environmental response actions. Refer to Note 18-C, “Environmental Matters,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding environmental matters for the Electric Operations segment.

Electric Operations sales quantities for the third quarter of 2011 were 4,726.0 gwh, a decrease of 110.5 gwh compared to the third quarter of 2010. The 2.3% decrease occurred primarily from lower wholesale, residential and commercial volumes. These decreases were partially offset by higher industrial volumes as a result of improvement in overall economic conditions.

Electric Operations sales quantities for the nine months ended September 30, 2011 were 13,354.7 gwh, an increase of 444.7 gwh compared to the same period in 2010. The 3.4% increase occurred primarily from higher industrial volumes as a result of improvement in overall economic conditions.

Net revenues were $250.4 million for the third quarter of 2011, a decrease of $6.8 million from the same period in 2010, primarily due to a decrease of $3.8 million related to weather, a decrease of $3.7 million in environmental trackers that are partly offset in operating expenses and a decrease of $3.5 million in residential and commercial margins. Additionally, there was a decrease of $2.8 million in off-system sales. These decreases were partially offset by an increase in industrial usage and margins of $3.5 million and lower revenue credits of $3.5 million compared to the prior year.

At Northern Indiana, customer billings and the related gross sales are adjusted for amounts related to under- and over-recovered purchased fuel costs from prior periods per regulatory order. These amounts are primarily reflected in the “Other” gross revenues statistic provided at the beginning of this segment discussion. The adjustment to Other gross revenues for the three and nine months ended September 30, 2011 was a revenue increase of $12.1 million and $2.7 million, respectively, compared to an increase of $12.9 million and $44.0 million for the three and nine months ended September 30, 2010, respectively.

Net revenues were $680.5 million for the nine months ended September 30, 2011, an increase of $8.3 million from the same period in 2010, primarily due to increased industrial usage and margins of $19.9 million resulting from improved economic conditions and $7.4 million in lower revenue credits compared to the prior year. These increases were partially offset by a decrease of $11.2 million in residential and commercial margins, a decrease of $3.7 million in environmental trackers that are partly offset in operating expense, and lower off-system sales of $3.6 million.

Operating income for the third quarter of 2011 was $78.8 million, a decrease of $17.1 million from the same period in 2010 due to higher operating expenses and lower net revenues described above. Operating expenses increased $10.3 million due primarily to the current period effects of a $6.0 million environmental reserve adjustment in the prior period, a $4.7 million write-off of rate case costs, and increased employee and administrative costs of $3.1 million. These increases were partially offset by a $4.9 million one-time inventory adjustment recorded in the prior period.

Operating income for the nine months ended September 30, 2011 was $161.8 million, a decrease of $28.8 from the same period in 2010, due to higher operating expenses partially offset by an increase in net revenues, as described above. Operating expenses increased $37.1 million due primarily to higher employee and administrative costs of $10.8 million, higher electric generation costs of $10.0 million as there were more outage weeks in the current period, a regulatory adjustment of $9.0 million, the current period effects of a $6.0 million environmental reserve adjustment in the prior period, and a $4.7 million write-off of rate case costs. These increases were partially offset by a $4.9 million one time inventory adjustment recorded in the prior period.

For a discussion regarding quantitative and qualitative disclosures about market risk see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”

NiSource’s Chief Executive Officer and its Principal Financial Officer, after evaluating the effectiveness of NiSource’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), have concluded based on the evaluation required by paragraph (b) of Exchange Act Rules 13a-15 and 15d-15 that, as of the end of the period covered by this report, NiSource’s disclosure controls and procedures are considered effective.

Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by NiSource in the reports that it files or submits under the Exchange Act is accumulated and communicated to NiSource’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no changes in NiSource’s internal control over financial reporting during the fiscal quarter covered by this report that has materially affected, or is reasonably likely to materially affect, NiSource’s internal control over financial reporting.

The consent decree was entered by the United States District Court for the Northern District of Indiana on July 22, 2011. The consent decree covers Northern Indiana’s four coal generating stations: Bailly, Michigan City, R.M. Schahfer, and D.H. Mitchell. Northern Indiana must surrender environmental permits for D.H. Mitchell’s coal-fired boilers, which have not been used to generate power since 2002. At the other generating stations, Northern Indiana must install additional control equipment, including three new SO2 control devices and one new NOx control device. The consent decree also imposes emissions limits for NOx, SO2, and particulate, and annual tonnage limits for NOx and SO2. In addition, Northern Indiana paid fines of $3.5 million in the third quarter of 2011, must surrender certain NOx and SO2 allowances, and invest $9.5 million in environmental mitigation projects. Northern Indiana is estimating the cost of NSR related capital improvements at $570 to $845 million, which will be expended between 2010 and 2018. Northern Indiana believes the capital costs will likely be recoverable from ratepayers.

In 1995, Columbia Transmission entered into an AOC with the EPA that requires Columbia Transmission to characterize and remediate environmental contamination at thousands of locations along Columbia Transmission’s pipeline system. One of the facilities subject to the AOC is the Majorsville Operations Center, which was remediated under an EPA approved Remedial Action Work Plan in summer 2008. Pursuant to the Remedial Action Work Plan, Columbia Transmission completed a project that stabilized residual oil contained in soils at the site and in sediments in an adjacent stream.

On April 23, 2009, however, the PADEP issued Columbia Transmission an NOV, alleging that the remediation was not effective. The NOV asserts violations of the Pennsylvania Clean Streams Law and the Pennsylvania Solid Waste Management Act and contains a settlement demand in the amount of $1 million. Columbia Transmission is unable to estimate the likelihood or cost of potential penalties or additional remediation at this time.

There were no material changes from the risk factors disclosed in NiSource’s 2010 10-K filed on February 28, 2011.

Pursuant to Item 601(b)(4)(iii) of Regulation S-K, NiSource hereby agrees to furnish the SEC, upon request, any instrument defining the rights of holders of long-term debt of NiSource not filed as an exhibit herein. No such instrument authorizes long-term debt securities in excess of 10% of the total assets of NiSource and its subsidiaries on a consolidated basis.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


Delaware		35-2108964
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

801 East 86th Avenue
Merrillville, Indiana		46410
(Address of principal executive offices)		(Zip Code)


		Page
Defined Terms			3

PART I FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited

	Condensed Statements of Consolidated Income (unaudited)		5

	Condensed Consolidated Balance Sheets (unaudited)		6

	Condensed Statements of Consolidated Cash Flows (unaudited)		8

	Condensed Statements of Consolidated Comprehensive Income (unaudited)		9

	Notes to Condensed Consolidated Financial Statements (unaudited)		10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		48

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		73

Item 4.	Controls and Procedures		73

PART II OTHER INFORMATION

Item 1.	Legal Proceedings		74

Item 1A.	Risk Factors		75

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		75

Item 3.	Defaults Upon Senior Securities		75

Item 4.	(Removed and Reserved)		75

Item 5.	Other Information		75

Item 6.	Exhibits		76

Signature			77


(in millions)	September 30, 2011			December 31, 2010
ASSETS
Property, Plant and Equipment
Utility Plant	$	20,095.5		$	19,494.9
Accumulated depreciation and amortization		(8,672.3	)		(8,492.6	)

Net utility plant		11,423.2			11,002.3

Other property, at cost, less accumulated depreciation		125.5			94.7

Net Property, Plant and Equipment		11,548.7			11,097.0

Investments and Other Assets
Assets of discontinued operations and assets held for sale		2.3			7.9
Unconsolidated affiliates		200.2			200.9
Other investments		164.3			139.7

Total Investments and Other Assets		366.8			348.5

Current Assets
Cash and cash equivalents		22.2			9.2
Restricted cash		180.1			202.9
Accounts receivable (less reserve of $29.7 and $37.4, respectively)		512.5			1,079.3
Income tax receivable		1.2			99.0
Gas inventory		467.0			298.2
Underrecovered gas and fuel costs		57.7			135.7
Materials and supplies, at average cost		87.0			83.8
Electric production fuel, at average cost		41.3			46.0
Price risk management assets		136.7			159.5
Exchange gas receivable		92.7			62.7
Regulatory assets		142.4			151.8
Prepayments and other		119.7			120.8

Total Current Assets		1,860.5			2,448.9

Other Assets
Price risk management assets		191.4			240.3
Regulatory assets		1,618.8			1,650.4
Goodwill		3,677.3			3,677.3
Intangible assets		300.4			308.6
Postretirement and postemployment benefits assets		43.6			35.1
Deferred charges and other		134.6			132.7

Total Other Assets		5,966.1			6,044.4

Total Assets	$	19,742.1			$19,938.8


(in millions, except share amounts)	September 30, 2011			December 31, 2010
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 281,111,006 and 278,855,291 shares issued and outstanding, respectively	$	2.8		$	2.8
Additional paid-in capital		4,149.4			4,103.9
Retained earnings		922.6			901.8
Accumulated other comprehensive loss		(54.4	)		(57.9	)
Treasury stock		(30.4	)		(27.4	)

Total Common Stockholders’ Equity		4,990.0			4,923.2
Long-term debt, excluding amounts due within one year		6,337.3			5,936.1

Total Capitalization		11,327.3			10,859.3

Current Liabilities
Current portion of long-term debt		8.2			34.2
Short-term borrowings		1,234.0			1,382.5
Accounts payable		244.4			581.8
Dividends payable		64.7			0.1
Customer deposits and credits		281.3			318.1
Taxes accrued		157.8			221.1
Interest accrued		67.7			114.4
Overrecovered gas and fuel costs		80.2			11.8
Price risk management liabilities		171.6			173.9
Exchange gas payable		178.3			266.1
Deferred revenue		3.5			6.8
Regulatory liabilities		88.8			92.9
Accrued liability for postretirement and postemployment benefits		23.3			23.3
Legal and environmental reserves		28.9			86.0
Other accruals		254.5			336.4

Total Current Liabilities		2,887.2			3,649.4

Other Liabilities and Deferred Credits
Price risk management liabilities		136.6			181.6
Deferred income taxes		2,430.2			2,209.7
Deferred investment tax credits		30.1			33.7
Deferred credits		79.0			68.6
Deferred revenue		—			0.3
Accrued liability for postretirement and postemployment benefits		874.4			1,039.6
Regulatory liabilities and other removal costs		1,643.7			1,595.8
Asset retirement obligations		140.5			138.8
Other noncurrent liabilities		193.1			162.0

Total Other Liabilities and Deferred Credits		5,527.6			5,430.1

Commitments and Contingencies (Refer to Note 18)		—			—

Total Capitalization and Liabilities	$	19,742.1			$19,938.8


Nine Months Ended September 30, (in millions)	2011			2010
Operating Activities
Net Income	$	278.8		$	258.6
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Depreciation and amortization		408.3			454.5
Net changes in price risk management assets and liabilities		14.1			(4.2	)
Deferred income taxes and investment tax credits		165.2			130.6
Deferred revenue		(4.2	)		(22.7	)
Stock compensation expense and 401(k) profit sharing contribution		27.4			23.2
Gain on sale of assets		(0.1	)		(0.1	)
Loss on impairment of assets		1.2			1.1
Income from unconsolidated affiliates		(8.0	)		(11.1	)
Gain on disposition of discontinued operations—net of taxes		—			(0.1	)
Loss from discontinued operations—net of taxes		1.8			0.3
Amortization of debt related costs		6.6			8.1
AFUDC equity		(3.2	)		(4.9	)
Distributions of earnings received from equity investees		10.9			7.9
Changes in Assets and Liabilities:
Accounts receivable		561.4			299.2
Income tax receivable		97.8			24.9
Inventories		(171.4	)		(32.8	)
Accounts payable		(325.1	)		(266.8	)
Customer deposits and credits		(36.8	)		(10.7	)
Taxes accrued		(62.8	)		(96.1	)
Interest accrued		(46.6	)		(40.0	)
Over (Under) recovered gas and fuel costs		146.4			(289.9	)
Exchange gas receivable/payable		(117.9	)		(12.9	)
Other accruals		(32.2	)		(22.7	)
Prepayments and other current assets		31.1			32.4
Regulatory assets/liabilities		39.2			103.9
Postretirement and postemployment benefits		(163.5	)		(142.3	)
Deferred credits		(2.0	)		(0.2	)
Deferred charges and other noncurrent assets		(6.3	)		9.9
Other noncurrent liabilities		32.6			(9.7	)

Net Operating Activities from Continuing Operations		842.7			387.4
Net Operating Activities used for Discontinued Operations		(48.6	)		(54.9	)

Net Cash Flows from Operating Activities		794.1			332.5

Investing Activities
Capital expenditures		(774.2	)		(553.7	)
Insurance recoveries		—			3.5
Proceeds from disposition of assets		9.4			0.3
Restricted cash withdrawals (deposits)		22.8			(101.8	)
Contributions to equity investees		(0.2	)		(87.7	)
Distributions from equity investees		—			23.8
Other investing activities		(59.7	)		(45.9	)

Net Investing Activities used for Continuing Operations		(801.9	)		(761.5	)
Net Investing Activities from Discontinued Operations		—			0.4

Net Cash Flow used for Investing Activities		(801.9	)		(761.1	)

Financing Activities
Issuance of long-term debt		395.3			—
Retirement of long-term debt		(36.5	)		(16.3	)
Premiums and other debt related costs		(8.2	)		—
Change in short-term borrowings, net		(148.5	)		621.6
Issuance of common stock		15.1			10.6
Acquisition of treasury stock		(3.1	)		(1.4	)
Dividends paid—common stock		(193.3	)		(191.4	)

Net Cash Flows from Financing Activities		20.8			423.1

Change in cash and cash equivalents from continuing operations		61.6			49.0
Cash contributions to discontinued operations		(48.6	)		(54.5	)
Cash and cash equivalents at beginning of period		9.2			16.4

Cash and Cash Equivalents at End of Period	$	22.2			$10.9


NiSource Subsidiaries and Affiliates
Capital Markets		NiSource Capital Markets, Inc.
CER		Columbia Energy Resources, Inc.
CGORC		Columbia Gas of Ohio Receivables Corporation
CNR		Columbia Natural Resources, Inc.
Columbia		Columbia Energy Group
Columbia Gulf		Columbia Gulf Transmission Company
Columbia of Kentucky		Columbia Gas of Kentucky, Inc.
Columbia of Maryland		Columbia Gas of Maryland, Inc.
Columbia of Massachusetts		Bay State Gas Company
Columbia of Ohio		Columbia Gas of Ohio, Inc.
Columbia of Pennsylvania		Columbia Gas of Pennsylvania, Inc.
Columbia of Virginia		Columbia Gas of Virginia, Inc.
Columbia Transmission		Columbia Gas Transmission, L.L.C.
CPRC		Columbia Gas of Pennsylvania Receivables Corporation
Crossroads Pipeline		Crossroads Pipeline Company
Granite State Gas		Granite State Gas Transmission, Inc.
Hardy Storage		Hardy Storage Company, L.L.C.
Kokomo Gas		Kokomo Gas and Fuel Company
Millennium		Millennium Pipeline Company, L.L.C.
NARC		NIPSCO Accounts Receivable Corporation
NDC Douglas Properties		NDC Douglas Properties, Inc.
NiSource		NiSource Inc.
NiSource Corporate Services		NiSource Corporate Services Company
NiSource Development Company		NiSource Development Company, Inc.
NiSource Finance		NiSource Finance Corp.
NiSource Midstream		NiSource Midstream Services, LLC
Northern Indiana		Northern Indiana Public Service Company
Northern Indiana Fuel and Light		Northern Indiana Fuel and Light Company
PEI		PEI Holdings, Inc.
Whiting Clean Energy		Whiting Clean Energy, Inc.

Abbreviations
AFUDC		Allowance for funds used during construction
AMRP		Accelerated Main Replacement Program
AOC		Administrative Order by Consent
AOCI		Accumulated other comprehensive income
ARP		Alternative Regulatory Plan
ARRs		Auction Revenue Rights
ASC		Accounting Standards Codification
BBA		British Banker Association
Bcf		Billion cubic feet
Board		Board of Directors
BPAE		BP Alternative Energy North America Inc
BTMU		The Bank of Tokyo-Mitsubishi UFJ, LTD.
BTU		British Thermal Unit
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
Ccf		Hundred cubic feet
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act (also known as Superfund)
Chesapeake		Chesapeake Appalachia, L.L.C.
CSAPR		Cross-State Air Pollution Rule
Day 2		Began April 1, 2005 and refers to the operational control of the energy markets by MISO, including the dispatching of wholesale electricity and generation, managing transmission constraints, and managing the day-ahead, real-time and financial transmission rights markets


DPU		Department of Public Utilities
DSM		Demand Side Management
Dth		Dekatherm
ECRM		Environmental Cost Recovery Mechanism
ECT		Environmental Cost Tracker
EERM		Environmental Expense Recovery Mechanism
EPA		United States Environmental Protection Agency
EPS		Earnings per share
FAC		Fuel adjustment clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		Flue Gas Desulfurization
FTRs		Financial Transmission Rights
GAAP		U.S. Generally Accepted Accounting Principles
GCR		Gas cost recovery
GHG		Greenhouse gases
gwh		Gigawatt hours
IDEM		Indiana Department of Environmental Management
IFRS		International Financial Reporting Standards
IRP		Infrastructure Replacement Program
IURC		Indiana Utility Regulatory Commission
LDCs		Local distribution companies
LIBOR		London InterBank Offered Rate
LIFO		Last in first out
Mcf		Million cubic feet
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator
Mitchell		Dean H. Mitchell Coal Fired Generating Station
MMDth		Million dekatherms
mw		Megawatts
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NO2		Nitrogen dioxide
NOx		Nitrogen oxide
NSR		New Source Review
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income (Loss)
OPEB		Other Postretirement and Postemployment Benefits
OUCC		Indiana Office of Utility Consumer Counselor
PADEP		Pennsylvania Department of Environmental Protection
Piedmont		Piedmont Natural Gas Company, Inc.
PJM		PJM Interconnection [is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.]
PM		particulate matter
PSC		Public Service Commission
PUC		Public Utility Commission
PUCO		Public Utilities Commission of Ohio
RBS		Royal Bank of Scotland PLC
RCRA		Resource Conservation and Recovery Act
RTO		Regional Transmission Organization
SEC		Securities and Exchange Commission
SIP		State Implementation Plan
SO2		Sulfur dioxide
VaR		Value-at-risk and instrument sensitivity to market factors
VIE		Variable Interest Entities
VSCC		Virginia State Corporation Commission


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, net of taxes)	2011			2010			2011		2010
Net Income	$	34.7		$	33.2		$	278.8	$	258.6
Other comprehensive income (loss)
Net unrealized (loss) gain on available-for-sale securities^(a)		(0.7	)		1.5			0.1		1.9
Net unrealized gain (loss) on cash flow hedges^(b),(c)		0.4			(0.7	)		2.1		(14.1	)
Unrecognized pension benefit and OPEB costs^(d)		0.4			2.3			1.3		0.7

Total other comprehensive income (loss)		0.1			3.1			3.5		(11.5	)

Total Comprehensive Income	$	34.8		$	36.3		$	282.3		$247.1


(in millions)
	Property, plant and
Assets of discontinued operations and held for sale:	equipment, net
Columbia Transmission	$	2.3

Total	$	2.3


(in millions)
Assets of discontinued operations and held for sale:	Property, plant and equipment, net
NiSource Corporate Services	$	5.6
Columbia Transmission		2.3

Total	$	7.9


	September 30, 2011		December 31, 2010
Commodity Price Risk Program:
Gas price volatility program derivatives (MMDth)		35.7		28.4
Price Protection Service program derivatives (MMDth)		1.5		1.6
DependaBill program derivatives (MMDth)		0.4		0.4
Regulatory incentive program derivatives (MMDth)		4.6		2.0
Gas marketing program derivatives (MMDth)^(a)		32.9		48.2
Gas marketing forward physical derivatives (MMDth)^(b)		32.4		48.0
Electric energy program FTR derivatives (mw)^(c)		11,846.7		8,279.1


(in millions)	September 30, 2011		December 31, 2010
	September 30, 2011		December 31, 2010
	Fair Value		Fair Value
Asset Derivatives
Balance Sheet Location
Derivatives designated as hedging instruments
Interest rate risk activities
Price risk management assets (current)	$	—	$	—
Price risk management assets (noncurrent)		57.7		61.1

Total derivatives designated as hedging instruments	$	57.7	$	61.1

Derivatives not designated as hedging instruments
Commodity price risk programs
Price risk management assets (current)	$	136.7	$	159.5
Price risk management assets (noncurrent)		133.7		179.2

Total derivatives not designated as hedging instruments	$	270.4	$	338.7

Total Asset Derivatives	$	328.1	$	399.8


	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)							Amount of Gain (Loss) Reclassified from AOCI into Income (Effective Portion)

							Location of Gain (Loss) Reclassified from AOCI into Income (Effective Portion)

Derivatives in Cash Flow Hedging Relationships	Sept. 30,			Sept. 30,				Sept. 30,			Sept. 30,
Derivatives in Cash Flow Hedging Relationships	2011			2010				2011			2010
Commodity price risk programs	$	(0.2	)	$	(0.5	)	Cost of Sales	$	0.1		$	0.1
Interest rate risk activities		0.4			0.4		Interest expense, net		(0.7	)		(0.7	)

Total	$	0.2		$	(0.1	)		$	(0.6	)	$	(0.6	)


Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from	Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)





	Effectiveness Testing)	Sept. 30, 2011		Sept. 30, 2010
Commodity price risk programs	Cost of Sales	$	—	$	—
Interest rate risk activities	Interest expense, net		—		—

Total		$	—	$	—


Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Amount of Gain (Loss) Recognized in Income on Derivatives
		Sept. 30, 2011			Sept. 30, 2010
Interest rate risk activities	Interest expense, net	$	(3.0	)	$	2.9

Total		$	(3.0	)	$	2.9


Derivatives in Fair Value Hedging Relationships	Location of (Loss) Gain Recognized in Income on Derivatives	Amount of (Loss) Gain Recognized in Income on Derivatives
		Amount of (Loss) Gain Recognized in Income on Derivatives
		Sept. 30, 2011			Sept. 30, 2010
Interest rate risk activities	Interest expense, net	$	(3.5	)	$	9.0

Total		$	(3.5	)	$	9.0


Hedged Item in Fair Value Hedge Relationships	Location of Gain (Loss) Recognized in Income on Related Hedged Item	Amount of Gain (Loss) Recognized in Income on Related Hedged Items

		Sept. 30, 2011		Sept. 30, 2010
Fixed-rate debt	Interest expense, net	$	3.0	$	(2.9	)

Total		$	3.0	$	(2.9	)


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Realized/Unrealized Gain (Loss) Recognized in Income on Derivatives *



		Sept. 30, 2011			Sept. 30, 2010
Commodity price risk programs	Gas Distribution revenues	$	(0.1	)	$	(0.1	)
Commodity price risk programs	Other revenues		16.6			43.4
Commodity price risk programs	Cost of Sales		(7.4	)		(38.8	)

Total		$	9.1		$	4.5


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Realized/Unrealized Gain (Loss) Recognized in Income on Derivatives *



		Sept. 30, 2011			Sept. 30, 2010
Commodity price risk programs	Gas Distribution revenues	$	(21.8	)	$	(21.6	)
Commodity price risk programs	Other revenues		35.0			116.1
Commodity price risk programs	Cost of Sales		(15.3	)		(106.4	)

Total		$	(2.1	)	$	(11.9	)


Recurring Fair Value Measurements September 30, 2011 (in millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of Sept. 30, 2011




Assets
Commodity Price risk management assets:
Physical price risk programs	$	—	$	133.1	$	—	$	133.1
Financial price risk programs		134.0		3.3		—		137.3
Interest rate risk activities		—		57.7		—		57.7
Available-for-sale securities		36.3		60.9		—		97.2

Total	$	170.3	$	255.0	$	—	$	425.3

Liabilities
Commodity Price risk management liabilities:
Physical price risk programs	$	—	$	3.4	$	—	$	2.4
Financial price risk programs		302.0		2.4		0.4		305.8

Total	$	302.0	$	5.8	$	0.4	$	308.2


Recurring Fair Value Measurements December 31, 2010 (in millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010




Assets
Commodity Price risk management assets:
Physical price risk programs	$	—	$	161.4	$	—	$	161.4
Financial price risk programs		173.8		3.2		0.3		177.3
Interest rate risk activities		—		61.1		—		61.1
Available-for-sale securities		43.5		37.9		—		81.4

Total	$	217.3	$	263.6	$	0.3	$	481.2

Liabilities
Commodity Price risk management liabilities:
Physical price risk programs	$	—	$	3.6	$	—	$	3.6
Financial price risk programs		348.5		3.3		0.1		351.9

Total	$	348.5	$	6.9	$	0.1	$	355.5


	Amortized		Total		Total			Fair
(in millions)	Cost		Gains		Losses			Value
Available-for-sale debt securities, Sept. 30, 2011
U.S. Treasury	$	40.2	$	1.6	$	—		$	41.8
Corporate/Other		54.2		1.5		(0.3	)		55.4

Total Available-for-sale debt securities	$	94.4	$	3.1	$	(0.3	)	$	97.2


	Financial
	Transmission		Other
Three Months Ended September 30, 2011 (in millions)	Rights		Derivatives			Total
Balance as of July 1, 2011	$	—	$	(0.8	)	$	(0.8	)

Total gains or (losses) (unrealized/realized)
Included in regulatory assets/liabilities		—		0.4			0.4
Purchases		—		(0.2	)		(0.2	)
Settlements		—		0.2			0.2

Balance as of September 30, 2011	$	—	$	(0.4	)	$	(0.4	)
Change in unrealized gains/(losses) relating to instruments still held as of September 30, 2011	$	—	$	(1.1	)	$	(1.1	)


	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30, (in millions)	2011			2010			2011			2010
Components of Net Periodic Benefit Cost
Service cost	$	9.4		$	9.8		$	2.5		$	2.5
Interest cost		29.9			31.5			9.6			10.6
Expected return on assets		(41.8	)		(36.0	)		(6.7	)		(6.1	)
Amortization of transition obligation		—			—			0.3			0.3
Amortization of prior service cost		0.1			0.5			(0.1	)		0.5
Recognized actuarial loss		13.9			14.4			1.7			1.7

Total Net Periodic Benefit Costs	$	11.5		$	20.2		$	7.3		$	9.5


	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30, (in millions)	2011			2010			2011			2010
Components of Net Periodic Benefit Cost
Service cost	$	28.2		$	29.3		$	7.5		$	7.3
Interest cost		89.7			94.3			28.8			31.8
Expected return on assets		(125.4	)		(107.8	)		(20.1	)		(18.0	)
Amortization of transition obligation		—			—			0.9			0.9
Amortization of prior service cost		0.3			1.5			(0.3	)		1.2
Recognized actuarial loss		41.7			43.4			5.1			4.7

Total Net Periodic Benefit Costs	$	34.5		$	60.7		$	21.9		$	27.9


	September 30,		December 31,
(in millions)	2011		2010
Commercial Paper weighted average interest rate of 0.98% at September 30, 2011	$	425.8	$	—
Credit facilities borrowings weighted average interest rate of 1.96% and 0.78% at September 30, 2011 and December 31, 2010, respectively		615.0		1,107.5
Accounts receivable securitization facility borrowings		193.2		275.0

Total short-term borrowings	$	1,234.0	$	1,382.5


(in millions)	Total		2011		2012		2013		2014		2015		After
Guarantees of subsidiaries debt	$	5,870.9	$	—	$	315.0	$	545.0	$	500.0	$	230.0	$	4,280.9
Guarantees supporting commodity transactions of subsidiaries		149.9		6.1		61.9		—		—		80.0		1.9
Accounts receivable securitization		193.2		193.2		—		—		—		—		—
Lines of credit		1,040.8		1,040.8		—		—		—		—		—
Letters of credit		37.4		0.4		35.8		0.2		1.0		—		—
Other guarantees		272.7		2.0		11.9		222.6		32.2		—		4.0

Total commercial commitments	$	7,564.9	$	1,242.5	$	424.6	$	767.8	$	533.2	$	310.0	$	4,286.8


(10.1)		Amended Restated Savings Restoration Plan for NiSource Inc. and Affiliates.

(10.2)		Amended and Restated NiSource Inc. Executive Deferred Compensation Plan effective.

(10.3)		Amended and Restated NiSource Inc. Supplemental Executive Retirement Plan effective.

(10.4)		Amended and Restated Pension Restoration Plan for NiSource Inc. and Affiliates effective.

(10.5)		Letter Agreement dated August 29, 2011 between Christopher A. Helms and NiSource Inc. or any of its affiliates or subsidiaries.

(31.1)		Certification of Robert C. Skaggs, Jr., Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)		Certification of Stephen P. Smith, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32.1)		Certification of Robert C. Skaggs, Jr., Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

(32.2)		Certification of Stephen P. Smith, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

(101.INS)		XBRL Instance Document

(101.SCH)		XBRL Schema Document

(101.CAL)		XBRL Calculation Linkbase Document

(101.LAB)		XBRL Labels Linkbase Document

(101.PRE)		XBRL Presentation Linkbase Document

(101.DEF)		XBRL Definition Linkbase Document


	NiSource Inc.
	(Registrant)

Date: October 28, 2011	By:	/S/ JON D. VEURINK
		Jon D. Veurink
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer and Duly Authorized Officer)