þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

NiSource Inc.

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)

(877) 647-5990
(Registrant’s telephone number, including area code)

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 o

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 o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer   o (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o 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: 274,592,165 shares outstanding at April 30, 2009.

 

 

		Page
Defined Terms			3
PART I FINANCIAL INFORMATION
Item 1. Financial Statements — unaudited			6
Condensed Statements of Consolidated Income (unaudited)			7
Condensed Consolidated Balance Sheets (unaudited)			8
Condensed Statements of Consolidated Cash Flows (unaudited)			9
Condensed Statements of Consolidated Comprehensive Income (unaudited)			10
Notes to Condensed Consolidated Financial Statements (unaudited)			11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			70
Item 3. Quantitative and Qualitative Disclosures About Market Risk			72
Item 4. Controls and Procedures			72
PART II OTHER INFORMATION
Item 1. Legal Proceedings			73
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. Submission of Matters to a Vote of Security Holders			75
Item 5. Other Information			75
Item 6. Exhibits			75
Signature			77
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

DEFINED TERMS

NiSource Subsidiaries and Affiliates
Bay State		Bay State Gas Company
Capital Markets		NiSource Capital Markets, Inc.
CER		Columbia Energy Resources, Inc.
CNR		Columbia Natural Resources, Inc.
Columbia		Columbia Energy Group
Columbia Energy Services		Columbia Energy Services Corporation
Columbia Gulf		Columbia Gulf Transmission Company
Columbia of Kentucky		Columbia Gas of Kentucky, Inc.
Columbia of Maryland		Columbia Gas of Maryland, Inc.
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 LLC
CORC		Columbia of Ohio 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
Lake Erie Land		Lake Erie Land Company
Millennium		Millennium Pipeline Company, L.L.C.
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.
Northern Indiana		Northern Indiana Public Service Company
Northern Indiana Fuel and Light		Northern Indiana Fuel and Light Company
NRC		NIPSCO Receivables Corporation
PEI		PEI Holdings, Inc.
TPC		EnergyUSA-TPC Corp.
Whiting Clean Energy		Whiting Clean Energy, Inc.
Abbreviations
AFUDC		Allowance for funds used during construction
AOC		Administrative Order by Consent
AOCI		Accumulated other comprehensive income
ARRs		Auction Revenue Rights
ASM		Ancillary Services Market
BART		Best Alternative Retrofit Technology
BBA		British Banker Association
Bcf		Billion cubic feet
Board		Board of Directors
BPAE		BP Alternative Energy North America Inc
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CCGT		Combined Cycle Gas Turbine
CERCLA		Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
Chesapeake		Chesapeake Appalachia, L.L.C.
CPCN		Certificate of Public Convenience and Necessity
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

DEFINED TERMS (continued)

DOT		United States Department of Transportation
DSM		Demand Side Management
Dth		Dekatherm
ECR		Environmental Cost Recovery
ECRM		Environmental Cost Recovery Mechanism
ECT		Environmental cost tracker
EER		Environmental Expense Recovery
EERM		Environmental Expense Recovery Mechanism
EITF No. 02-3		Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
EPA		United States Environmental Protection Agency
EPS		Earnings per share
FAC		Fuel adjustment clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN 47		FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”
FIN 48		FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
FSP		FASB Staff Position
FSP FAS 107-1 and APB 28-1		FASB Staff Position FAS 107-1 and APB 28-1: Interim Disclosures about Fair Value of Financial Instruments
FSP FAS 115-2 and FAS 124-2		FASB Staff Position FAS 115-2 and FAS 124-2: Recognition and Presentation of Other-Than-Temporary Impairments
FSP FAS 132(R)-1		FASB Staff Position FAS 132 (R)-1: Employers’ Disclosures About Postretirement Benefit Plan Assets
FSP FAS 140-4 and FIN 46(R)-8		FASB Staff Position FAS 140-4 and FASB Interpretation No. 46(R): Disclosures about Transfers of Financial Assets and Interests in Variable Interest Entities
FSP FAS 141(R)-1		FASB Staff Position FAS 141(R)-1: Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies
FSP FAS 157-2		FASB Staff Position FAS 157-2: Effective Date of FASB Statement No. 157
FSP FAS 157-3		FASB Staff Position FAS 157-3: Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active
FSP FAS 157-4		FASB Staff Position FAS 157-4: Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly
FTRs		Financial Transmission Rights
GAAP		U.S. Generally Accepted Accounting Principles
gwh		Gigawatt hours
hp		Horsepower
IDEM		Indiana Department of Environmental Management
IURC		Indiana Utility Regulatory Commission
LDCs		Local distribution companies
LIBOR		London InterBank Offered Rate
LIFO		Last-in, first-out
MGP		Manufactured gas plant
MISO		Midwest Independent Transmission System Operator
mmBtu		million British thermal units
MMDth		Million dekatherms
mw		Megawatts
NAAQS		National Ambient Air Quality Standards

DEFINED TERMS (continued)

NOV		Notice of Violation
NOx		Nitrogen oxide
NPDES		National Pollutant Discharge Elimination System
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income (Loss)
OUCC		Indiana Office of Utility Consumer Counselor
PADEP		Pennsylvania Department of Environmental Protection
PAL		parking and lending services
PCB		Polychlorinated biphenyls
Piedmont		Piedmont Natural Gas Company, Inc.
PIPP		Percentage of Income Plan
PPUC		Pennsylvania Public Utility Commission
PSC		Public Service Commission
PUCO		Public Utilities Commission of Ohio
RCRA		Resource Conservation and Recovery Act
RSG		Revenue Sufficiency Guarantee
SAB No. 92		Staff Accounting Bulletin No. 92, “Accounting and Disclosures Relating to Loss Contingencies”
SEC		Securities and Exchange Commission
SFAS No. 5		Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”
SFAS No. 71		Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 109		Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
SFAS No. 132(R)		Statement of Financial Accounting Standards No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits — an amendment of FASB No. 87, 88, and 106”
SFAS No. 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended
SFAS No. 140		Statement of Financial Accounting Standards No. 140, “Accounting for Transfers and Servicing of Financial Asset and Extinguishments of Liabilities”
SFAS No. 141R		Statement of Financial Accounting Standards No. 141R, “Business Combinations”
SFAS No. 142		Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 143		Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”
SFAS No. 160		Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51”
SFAS No. 161		Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging — an amendment of SFAS No. 133”
SIP		State Implementation Plan
SO2		Sulfur dioxide
SOP 96-1		Statement of Position 96-1, “Environmental Remediation Liabilities”
VaR		Value-at-risk and instrument sensitivity to market factors

ITEM 1. FINANCIAL STATEMENTS

Three Months Ended March 31, (in millions, except per share amounts)		2009				2008
Net Revenues
Gas Distribution		$	1,716.9			$	2,229.7
Gas Transportation and Storage			396.2				357.2
Electric			296.8				331.8
Other			310.3				370.0
Gross Revenues			2,720.2				3,288.7
Cost of Sales (excluding depreciation and amortization)			1,654.8				2,248.0
Total Net Revenues			1,065.4				1,040.7
Operating Expenses
Operation and maintenance			478.3				410.1
Depreciation and amortization			143.8				135.6
Impairment and (gain)/loss on sale of assets			(2.0	)			(1.5	)
Other taxes			103.4				103.6
Total Operating Expenses			723.5				647.8
Equity Earnings in Unconsolidated Affiliates			6.4				2.0
Operating Income			348.3				394.9
Other Income (Deductions)
Interest expense, net			(90.5	)			(91.8	)
Gain on early extinguishment of long-term debt			3.2				—
Other, net			(4.2	)			(1.5	)
Total Other Income (Deductions)			(91.5	)			(93.3	)
Income From Continuing Operations Before Income Taxes			256.8				301.6
Income Taxes			97.5				112.1
Income from Continuing Operations			159.3				189.5
Income (Loss) from Discontinued Operations — net of taxes			(10.7	)			6.0
Loss on Disposition of Discontinued Operations — net of taxes			(0.2	)			(96.2	)
Net Income		$	148.4			$	99.3
Basic Earnings (Loss) Per Share
Continuing operations		$	0.58			$	0.69
Discontinued operations			(0.04	)			(0.33	)
Basic Earnings Per Share		$	0.54			$	0.36
Diluted Earnings (Loss) Per Share
Continuing operations		$	0.58			$	0.69
Discontinued operations			(0.04	)			(0.33	)
Diluted Earnings Per Share		$	0.54			$	0.36
Dividends Declared Per Common Share		$	0.46			$	0.46
Basic Average Common Shares Outstanding			274.2				273.9
Diluted Average Common Shares			276.7				275.4

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

ITEM 1. FINANCIAL STATEMENTS (continued)

		March 31,				December 31,
(in millions)		2009				2008
ASSETS
Property, Plant and Equipment
Utility Plant		$	18,498.2			$	18,356.8
Accumulated depreciation and amortization			(8,134.1	)			(8,080.8	)
Net utility plant			10,364.1				10,276.0
Other property, at cost, less accumulated depreciation			112.6				112.1
Net Property, Plant and Equipment			10,476.7				10,388.1
Investments and Other Assets
Assets of discontinued operations and assets held for sale			46.6				45.8
Unconsolidated affiliates			114.1				86.8
Other investments			115.7				117.9
Total Investments and Other Assets			276.4				250.5
Current Assets
Cash and cash equivalents			135.2				20.6
Restricted cash			316.8				286.6
Accounts receivable (less reserve of $69.8 and $45.3, respectively)			910.7				1,142.5
Gas inventory			87.0				511.8
Underrecovered gas and fuel costs			0.5				180.2
Materials and supplies, at average cost			96.3				95.1
Electric production fuel, at average cost			76.0				63.8
Price risk management assets			173.5				150.4
Exchange gas receivable			257.4				393.8
Regulatory assets			285.8				314.9
Assets of discontinued operations and assets held for sale			2.2				2.0
Prepayments and other			291.0				249.1
Total Current Assets			2,632.4				3,410.8
Other Assets
Price risk management assets			204.2				200.7
Regulatory assets			1,628.2				1,640.4
Goodwill			3,677.3				3,677.3
Intangible assets			327.8				330.6
Postretirement and postemployment benefits assets			9.6				10.3
Deferred charges and other			117.4				123.5
Total Other Assets			5,964.5				5,982.8
Total Assets		$	19,350.0			$	20,032.2

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

NiSource Inc.
Condensed Consolidated Balance Sheets (unaudited) (continued)

		March 31,				December 31,
(in millions, except share amounts)		2009				2008
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stockholders’ Equity
Common stock — $0.01 par value, 400,000,000 shares authorized; 274,500,339 and 274,261,799 shares issued and outstanding, respectively		$	2.7			$	2.7
Additional paid-in capital			4,023.0				4,020.3
Retained earnings			923.3				901.1
Accumulated other comprehensive loss			(187.2	)			(172.0	)
Treasury stock			(24.1	)			(23.3	)
Total Common Stockholders’ Equity			4,737.7				4,728.8
Long-term debt, excluding amounts due within one year			6,451.9				5,943.9
Total Capitalization			11,189.6				10,672.7
Current Liabilities
Current portion of long-term debt			436.0				469.3
Short-term borrowings			—				1,163.5
Accounts payable			531.6				693.3
Dividends declared			63.2				—
Customer deposits			130.7				127.3
Taxes accrued			259.4				206.5
Interest accrued			96.7				120.1
Overrecovered gas and fuel costs			302.5				35.9
Price risk management liabilities			336.0				286.5
Exchange gas payable			339.0				555.5
Deferred revenue			11.0				14.7
Regulatory liabilities			40.2				40.4
Accrued liability for postretirement and postemployment benefits			6.4				6.4
Liabilities of discontinued operations and liabilities held for sale			2.3				1.5
Temporary LIFO liquidation credit			111.3				—
Legal and environmental reserves			322.4				375.1
Other accruals			289.3				487.4
Total Current Liabilities			3,278.0				4,583.4
Other Liabilities and Deferred Credits
Price risk management liabilities			195.4				188.5
Deferred income taxes			1,606.2				1,549.8
Deferred investment tax credits			44.5				46.1
Deferred credits			76.1				76.7
Deferred revenue			6.8				6.2
Accrued liability for postretirement and postemployment benefits			1,248.5				1,238.5
Liabilities of discontinued operations and liabilities held for sale			4.2				4.4
Regulatory liabilities and other removal costs			1,411.2				1,386.1
Asset retirement obligations			125.7				126.0
Other noncurrent liabilities			163.8				153.8
Total Other Liabilities and Deferred Credits			4,882.4				4,776.1
Commitments and Contingencies (Refer to Note 16)			—				—
Total Capitalization and Liabilities		$	19,350.0			$	20,032.2

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

ITEM 1. FINANCIAL STATEMENTS (continued)

		2009				2008
Operating Activities
Net Income		$	148.4			$	99.3
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Gain on Early Extinguishment of Debt			(3.2	)			—
Depreciation and Amortization			143.8				135.6
Net Changes in Price Risk Management Assets and Liabilities			(1.7	)			(9.6	)
Deferred Income Taxes and Investment Tax Credits			23.1				16.7
Deferred Revenue			(3.7	)			(16.3	)
Stock Compensation Expense			1.6				1.4
Gain on Sale of Assets			(2.0	)			(3.2	)
Loss on Impairment of Assets			—				1.6
Income from Unconsolidated Affiliates			(6.4	)			(1.7	)
Loss on Disposition of Discontinued Operations — Net of Taxes			0.2				96.1
Loss (Income) from Discontinued Operations — Net of Taxes			10.7				(6.0	)
Amortization of Discount/Premium on Debt			2.1				1.8
AFUDC Equity			0.9				(1.1	)
Changes in Assets and Liabilities:
Accounts Receivable			172.1				(152.9	)
Inventories			487.7				847.3
Accounts Payable			(161.1	)			32.1
Customer Deposits			3.4				1.6
Taxes Accrued			82.0				128.4
Interest Accrued			(23.4	)			(9.0	)
(Under) Overrecovered Gas and Fuel Costs			446.3				(93.1	)
Exchange Gas Receivable/Payable			(80.1	)			(44.0	)
Other Accruals			(187.4	)			(120.9	)
Prepayments and Other Current Assets			8.8				3.7
Regulatory Assets/Liabilities			32.3				(36.4	)
Postretirement and Postemployment Benefits			11.3				18.8
Deferred Credits			(3.4	)			(5.6	)
Deferred Charges and Other NonCurrent Assets			11.8				(7.5	)
Other Non Current Liabilities			5.7				(29.0	)
Net Operating Activities from Continuing Operations			1,119.8				848.1
Net Operating Activities used for Discontinued Operations			(61.9	)			(2.1	)
Net Cash Flows from Operating Activities			1,057.9				846.0
Investing Activities
Capital Expenditures			(206.9	)			(196.9	)
Insurance Recoveries			52.0				6.2
Proceeds from Disposition of Assets			2.1				12.5
Restricted Cash			(30.2	)			72.1
Other Investing Activities			(20.9	)			(1.4	)
Net Investing Activities used for Continuing Operations			(203.9	)			(107.5	)
Net Investing Activities from Discontinued Operations			7.5				2.9
Net Cash Flows used for Investing Activities			(196.4	)			(104.6	)
Financing Activities
Issuance of Long-Term Debt			581.7				0.9
Retirement of Long-Term Debt			(101.4	)			(1.0	)
Repurchase of Long-Term Debt			—				(199.0	)
Change in Short-Term Debt, Net			(1,163.5	)			(436.3	)
Issuance of Common Stock			0.2				0.6
Acquisition of Treasury Stock			(0.8	)			—
Dividends Paid — Common Stock			(63.1	)			(63.1	)
Net Cash Flows used for Financing Activities			(746.9	)			(697.9	)
Increase in cash and cash equivalents from continuing operations			169.0				43.5
Cash contributions to discontinued operations			(54.4	)			(0.7	)
Cash and cash equivalents at beginning of period			20.6				34.6
Cash and Cash Equivalents at End of Period		$	135.2			$	77.4

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

ITEM 1. FINANCIAL STATEMENTS (continued)

Three Months Ended March 31, (in millions, net of taxes)		2009				2008
Net Income		$	148.4			$	99.3
Other comprehensive income (loss)
Net loss on available for sale securities (a)			(1.3	)			(1.3	)
Net unrealized gains (losses) on cash flow hedges (b)			(14.5	)			17.3
Unrecognized pension benefit and other postretirement benefit costs (c)			0.6				(3.6	)
Total other comprehensive income (loss)			(15.2	)			12.4
Total Comprehensive Income		$	133.2			$	111.7

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

ITEM 1. FINANCIAL STATEMENTS (continued)

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, 2008. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The following 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.

SFAS No. 161 — Disclosures about Derivative Instruments and Hedging — an amendment of SFAS No. 133. In March 2008, the FASB issued SFAS No. 161 to amend and expand the disclosure requirements of SFAS No. 133 with the intent to provide users of the financial statement with an enhanced understanding of how and why an entity uses derivative instruments, how these derivatives are accounted for and how the respective reporting entity’s financial statements are affected. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008, and earlier application is encouraged. NiSource adopted this standard on January 1, 2009. Refer to Note 9, “Risk Management Activities,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.

SFAS No. 160 — Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. In December 2007, the FASB issued SFAS No. 160 to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements regarding non-controlling ownership interests in a business and for the deconsolidation of a subsidiary. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. The adoption of this standard on January 1, 2009 did not have a material impact on the Condensed Consolidated Financial Statements (unaudited).

SFAS No. 157 — Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 does not change the requirements to apply fair value in existing accounting standards.

Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability.

To increase consistency and comparability in fair value measurements, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The level in the fair value hierarchy disclosed is based on the lowest level of input that is significant to the fair value measurement. The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

	•		Level 1 inputs are quoted prices (unadjusted) in active markets for identical asset or liabilities that the company has the ability to access as of the reporting date.

ITEM 1. FINANCIAL STATEMENTS (continued)

	•		Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data.
	•		Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.

SFAS No. 157 became effective for NiSource as of January 1, 2008. The provisions of SFAS No. 157 were applied prospectively, except for the initial impact on the following three items, which were required to be recorded as an adjustment to the opening balance of retained earnings in the year of adoption: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF No. 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts. The adoption of SFAS No. 157 did not have an impact on NiSource’s January 1, 2008 balance of retained earnings.

In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of non-financial assets and liabilities until fiscal years beginning after November 15, 2008.

In October 2008, the FASB issued FSP FAS 157-3, which clarified the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued.

Refer to Note 10, “Fair Value Assets and Liabilities,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding the adoption of SFAS No. 157.

SFAS No. 141R — Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. The adoption of this standard on January 1, 2009 did not have a material impact on the Condensed Consolidated Financial Statements (unaudited).

In April 2009, the FASB issued FSP FAS 141(R)-1, which amends and clarifies SFAS No. 141 to address application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.

FSP FAS 140-4 and FIN 46(R)-8- FASB Staff Position Amendment of FASB Statement No. 140 and FASB Interpretation No. 46(R). In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 to require public entities to provide additional disclosures about transfers of financial assets and to provide additional disclosures related to an entities involvement with variable interest entities. This FSP is effective for the first reporting period ending after December 15, 2008, with early application encouraged. The adoption of this FSP on January 1, 2009 did not have a material impact on the Condensed Consolidated Financial Statements (unaudited).

Recently Issued Accounting Pronouncements

FSP FAS 107-1 and APB 28-1 — FASB Staff Position Amendment of FASB Statement No. 107 and APB Opinion No. 28. In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1 to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted. NiSource is currently reviewing the additional disclosure requirements to determine the impact on the

ITEM 1. FINANCIAL STATEMENTS (continued)

Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements.

FSP FAS 115-2 and FAS 124-2 — FASB Staff Position Amendment of FASB Statement No. 115 and FASB Statement No. 124. In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2 to amend the other-than-temporary impairment guidance in GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted. NiSource is currently reviewing the additional disclosure requirements to determine the impact on the Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements.

FSP FAS 132(R)-1 — FASB Staff Position Amendment of FASB Statement No. 132(R)-1. In December 2008, the FASB issued FSP FAS 132(R)-1 to amend SFAS No. 132(R), to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009 with earlier adoption permitted. NiSource is currently reviewing the additional disclosure requirements to determine the impact on the Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements.

FSP FAS 157-4 — FASB Staff Position Amendment of FASB Statement No. 157. In April 2009, the FASB issued FSP FAS 157-4 to provide additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted. NiSource is currently reviewing the additional guidance to determine the impact on the Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements.

3. Earnings Per Share

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 include the incremental effects of the various long-term incentive compensation plans. The numerator in calculating both basic and diluted EPS for each period is reported net income. The computation of diluted average common shares follows:

Three Months Ended March 31, (in thousands)		2009				2008
Denominator
Basic average common shares outstanding			274,196				273,922
Dilutive potential common shares
Shares contingently issuable under employee stock plans			2,413				1,271
Shares restricted under employee stock plans			108				174
Diluted Average Common Shares			276,717				275,367

4. Restructuring Activities

In response to the current economic conditions, on February 27, 2009, NiSource announced an organizational restructuring of the Gas Transmission and Storage Operations segment. NiSource is eliminating positions across the 16 state operating territory of Gas Transmission and Storage. The reductions will occur through voluntary programs and involuntary separations. In addition to employee reductions, the Gas Transmission and Storage Operations segment will take steps to achieve additional cost savings by efficiently managing its various business locations, reducing its fleet operations, creating alliances with third party service providers, and implementing other changes in line with its strategic plan for growth and maximizing value of existing assets. During the first quarter of 2009,

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource recorded a pre-tax restructuring charge of $19.8 million to “Operation and maintenance” expense on the Condensed Statement of Consolidated Income (unaudited), which primarily includes costs related to severance and other employee related costs for approximately 350 employees. NiSource expects this restructuring initiative to be substantially complete by the end of 2009.

Restructuring reserve by restructuring initiative:

		Balance at												Balance at
(in millions)		December 31, 2008				Additions				Benefits Paid				March 31, 2009
Gas Transmission and Storage initiative			—				19.8				(0.8	)			19.0
Total		$	—			$	19.8			$	(0.8	)		$	19.0

Gas Distribution Operations price natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, NiSource expects interim variances in LIFO layers to be replenished by year-end. Changes between the temporary LIFO liquidation credits in the amounts of $111.3 million and $472.3 million during the first quarter of 2009 and 2008, respectively, are considered a non-cash activity for the Condensed Statements of Consolidated Cash Flow (unaudited). In addition to the temporary LIFO liquidation credit described above NiSource also has a temporary LIFO liquidation debit of $34.3 million recorded for the first quarter of 2009 for certain gas distribution companies recorded within, “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

The assets and liabilities of discontinued operations and held for sale on the Condensed Consolidated Balance Sheet (unaudited) at March 31, 2009 were:

(in millions)
Assets of discontinued operations		Property, plant and				Accounts receivable,
and held for sale:		equipment, net				net				Other assets				Total
Bay State Gas Company		$	21.6			$	—			$	—			$	21.6
Lake Erie Land			11.9				—				—				11.9
NiSource Corporate Services			6.2				—				—				6.2
NDC Douglas Properties			4.0				—				1.2				5.2
Columbia Transmission			2.6				—				—				2.6
NiSource Retail Service Corp			0.3				1.0				—				1.3
Total		$	46.6			$	1.0			$	1.2			$	48.8
Liabilities of discontinued operations and held for sale:		Debt				Accounts payable				Other liabilities				Total
NDC Douglas Properties		$	4.9			$	0.4			$	0.3			$	5.6
NiSource Retail Service Corp			—				0.9				—				0.9
Total		$	4.9			$	1.3			$	0.3			$	6.5

ITEM 1. FINANCIAL STATEMENTS (continued)

The assets and liabilities of discontinued operations and held for sale on the Consolidated Balance Sheet at December 31, 2008 were:

(in millions)
Assets of discontinued		Property, plant and				Accounts receivable,
operations and held for sale:		equipment, net				net				Other assets				Total
Bay State Gas Company		$	20.8			$	—			$	—			$	20.8
Lake Erie Land			11.9				—				—				11.9
NiSource Corporate Services			6.2				—				—				6.2
NDC Douglas Properties			4.1				—				1.0				5.1
Columbia Transmission			2.6				—				—				2.6
NiSource Retail Service Corp			0.3				0.9				—				1.2
Total		$	45.9			$	0.9			$	1.0			$	47.8
Liabilities of discontinued operations and held for sale:		Debt				Accounts payable				Other liabilities				Total
NDC Douglas Properties		$	4.9			$	0.2			$	0.2			$	5.3
NiSource Retail Service Corp			—				0.6				—				0.6
Total		$	4.9			$	0.8			$	0.2			$	5.9

Assets classified as discontinued operations or held for sale are no longer depreciated.

On June 30, 2008, NiSource sold Whiting Clean Energy to BPAE for $216.7 million, which included $16.1 million in working capital. In the first quarter of 2008, NiSource began accounting for the operations of Whiting Clean Energy as discontinued operations. For the three months ended March 31, 2008, an after tax loss of $32.5 million was included in Loss on Disposition of Discontinued Operations in the Statements of Consolidated Income.

On December 1, 2008, NiSource sold NiSource subsidiaries Northern Utilities and Granite State to Unitil Corporation. The final sale amount was $209.1 million which included $49.1 million in working capital. Under the terms of the transaction, Unitil Corporation acquired Northern Utilities, a local gas distribution company serving 52 thousand customers in 44 communities in Maine and New Hampshire and Granite State Gas, an 86-mile FERC regulated gas transmission pipeline primarily located in Maine and New Hampshire. For the three months ended March 31, 2008, an after tax loss of $63.5 million was included in Gain (Loss) on Disposition of Discontinued Operations in the Condensed Statements of Consolidated Income (unaudited). A loss of $0.7 million and income of $6.0 million is included as net income or loss from discontinued operations for the three months ended March 31, 2009 and 2008, respectively.

NDC Douglas Properties, a subsidiary of NiSource Development Company, is in the process of exiting some of its low income housing investments. NiSource has accounted for the investments to be sold as assets and liabilities of discontinued operations and held for sale.

NiSource Corporate Services is continuing to work with several potential buyers to sell its Marble Cliff facility. A third party appraisal was performed in December 2008 with an estimated market value of the property of $6.2 million, which equals the book value. NiSource has accounted for this facility as assets held for sale.

Lake Erie Land, which is wholly-owned by NiSource, is in the process of selling real estate over a 10-year period with a private real estate development group extending through 2016. NiSource estimates the property to be sold to the private developer during the next twelve months and accounts for these assets as assets held for sale.

During the second quarter of 2008, Bay State signed a letter of intent to sell certain assets, including water heater rentals and other service agreements. During April 2009, negotiations with a potential buyer were terminated. NiSource still estimates that the property will be sold within twelve months and therefore, continues to account for these assets as assets held for sale.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Retail Services, a wholly-owned subsidiary of NiSource, is engaged in a process to sell certain assets. During April 2009 negotiations with a potential buyer were terminated. NiSource still estimates the property to be sold within twelve months and therefore continues to account for these assets as assets held for sale.

Results from discontinued operations from Whiting Clean Energy, Granite State Gas, Northern Utilities, NDC Douglas Properties low income housing investments, NiSource Retail Services, and reserve changes for NiSource’s former exploration and production subsidiary, CER, are provided in the following table:

Three Months Ended March 31, (in millions)		2009				2008
Revenues from Discontinued Operations		$	2.3			$	102.3
(Loss) Income from discontinued operations			(17.4	)			10.1
Income tax (benefit) expense			(6.7	)			4.1
(Loss) Income from Discontinued Operations — net of taxes		$	(10.7	)		$	6.0
Loss on Disposition of Discontinued Operations - net of taxes		$	(0.2	)		$	(96.2	)

The loss on disposition of discontinued operations for the three months ended March 31, 2008 include the after tax loss on disposition related to the sales of Whiting Clean Energy, Northern Utilities and Granite State Gas of $32.5 million, $48.8 million and $14.8 million, respectively.

7. Asset Retirement Obligations

NiSource accounts for its asset retirement obligations in accordance with SFAS No. 143 and FIN 47. 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 first quarters of 2009 and 2008 are presented in the table below:

Three Months Ended March 31, (in millions)		2009				2008
Balance as of January 1, 2009		$	126.0			$	128.2
Accretion expense			0.2				0.2
Accretion recorded as a regulatory asset			1.7				1.2
Settlements			(2.2	)			—
Balance as of March 31, 2009		$	125.7			$	129.6

8. Regulatory Matters

Gas Distribution Operations Regulatory Matters

Significant Rate Developments. Columbia of Ohio filed a base rate case with the PUCO on March 3, 2008, and a settlement agreement was filed on October 24, 2008. In the base rate case, Columbia of Ohio sought recovery of increased infrastructure rehabilitation costs, as well as the stabilization of revenues and cost recovery through rate design. The agreement included an annual revenue increase of $47.1 million, and also provides for recovery of costs associated with Columbia of Ohio’s infrastructure rehabilitation program. On December 3, 2008, the PUCO approved the settlement agreement in all material respects, and approved Columbia of Ohio’s proposed rate design. On February 27, 2009, Columbia of Ohio filed an application to adjust its Infrastructure Replacement Program Rider by approximately $15 million covering increased costs for risers and accelerated main replacements. This matter is currently pending.

ITEM 1. FINANCIAL STATEMENTS (continued)

On January 15, 2009, Columbia of Ohio filed an application with the PUCO requesting authority to increase Columbia of Ohio’s PIPP rider rate in order to collect $82.2 million in PIPP arrearages. On March 3, 2009, Columbia of Ohio’s proposal was approved and became effective.

On January 28, 2008, Columbia of Pennsylvania filed a base rate case with the PPUC seeking recovery of costs associated with its significant infrastructure rehabilitation program, as well as stabilization of revenues through modifications to rate design. On July 2, 2008, Columbia of Pennsylvania and all interested parties filed a unanimous settlement and on October 23, 2008, the PPUC issued an Order approving the settlement as filed, increasing annual revenues by $41.5 million.

On April 16, 2009, Bay State filed a base rate case with the Massachusetts Department of Public Utilities, requesting an increase of $34.6 million. In its filing, Bay State is seeking revenue decoupling, as well as an expedited mechanism for the recovery of costs associated with the rehabilitation of the company’s infrastructure. This matter is currently pending and expected to be resolved with new rates taking effect in the fourth quarter 2009.

On May 1, 2009, Columbia of Kentucky filed a base rate case with the Kentucky PSC, requesting an annual increase of $11.6 million. In its initial filing, Columbia of Kentucky is seeking enhancements to rate design, as well as an expedited mechanism for the recovery of costs associated with the rehabilitation of the company’s infrastructure. This matter is currently pending.

On October 1, 2008, Columbia of Maryland filed a base rate case with the Maryland PSC. On February 20, 2009, Columbia of Maryland and all interested parties filed a unanimous settlement in the case, recommending an annual revenue increase of $1.2 million. On March 27, 2009, the settlement was approved as filed.

On November 24, 2008 Northern Indiana filed Supplemental Testimony in its annual gas cost recovery proceeding (GCA 10-Cause No. 41338) seeking a cost recovery mechanism for Unaccounted for Gas at current gas prices. Historically, in Indiana, Unaccounted for Gas recovery mechanisms are determined within a base rate proceeding. Intervenors have filed testimony, opposing recovery of Unaccounted for Gas in the gas cost adjustment proceeding and disputing the calculation of Unaccounted for Gas. Evidentiary hearings were held on April 20 and 21, 2009. An order is expected in the third quarter of 2009.

In March 2009, Indiana Governor Daniels signed Senate Bill 423 into law giving the Indiana Finance Authority the authority 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 is seeking bids to initiate a Substitute Natural Gas plant in Southern Indiana under a 30 year contract. It is expected that all Indiana gas utilities including Northern Indiana will be delivering a portion of Substitute Natural Gas from this facility. The IURC must approve the final contract.

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 gas cost recovery adjustment mechanisms, tax riders, and bad debt recovery mechanisms.

Comparability of Gas Distribution Operations line item operating results is impacted by these 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.

ITEM 1. FINANCIAL STATEMENTS (continued)

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. Columbia of Ohio and Columbia of Pennsylvania completed rate cases in 2008 incorporating significant infrastructure replacement programs and other NiSource gas distribution utilities are currently evaluating requests for increases in rates in order to allow recovery of the additional capital expenditures required for such initiatives. Each LDC’s approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.

On April 9, 2008, the PUCO issued an order approving, in all material respects, a joint stipulation submitted on behalf of Columbia of Ohio. This stipulation is a result of a process that began on April 13, 2005 with a PUCO ordered investigation into the type of gas risers installed in the state, the conditions of installation and overall performance. The stipulation provides for: establishment of accounting for and recovery of costs resulting from the Staff’s investigation; Columbia of Ohio’s performance of a survey to identify those customer-owned risers on its system prone to failure; and related customer education and other program related expenses. In addition this stipulation provides for: Columbia of Ohio’s assumption of financial responsibility for the replacement of all risers identified as prone to failure; repair or replacement of hazardous customer owned service lines; and capitalization of this investment with recovery to be addressed in future rate proceedings. As of March 31, 2009, Columbia of Ohio has approximately $62.1 million in costs associated with the gas riser and customer service line programs recorded as either a regulatory asset or capitalized plant.

On December 28, 2007, Columbia of Ohio entered into a stipulation with the Ohio Consumers’ Counsel and PUCO Staff and other stakeholders resolving litigation concerning a pending Gas Cost Recovery audit of Columbia of Ohio. The stipulation calls for an accelerated pass back to customers of $36.6 million, occurring from January 31, 2008 through January 31, 2009, generated through off-system sales and capacity release programs, the development of new energy efficiency programs for introduction in 2009, and the development of a wholesale auction process for customer supply to take effect in 2010. The entire requirement of the stipulation was passed back through January 31, 2009. The stipulation also resolves issues related to pending and future Gas Cost Recovery Management Performance audits through 2008. The PUCO approved this agreement on January 23, 2008.

On April 23, 2009, Columbia of Kentucky filed an application with the Kentucky PSC to defer pension and other postretirement benefits expenses above those currently subject to collection in rates. If approved, the amount deferred would be approximately $1.2 million for 2009. This matter is currently pending.

On April 30, 2009, Columbia of Ohio filed an application with the PUCO to defer pension and other postretirement benefits expenses above those currently subject to collection in rates. If approved, the amount deferred would be approximately $14.6 million for 2009. This matter is currently pending.

Gas Transmission and Storage Operations Regulatory Matters

Eastern Market Expansion Project. On January 14, 2008, the FERC issued an order which granted a certificate to construct the project. The project allows Columbia Transmission to expand its facilities to provide additional storage and transportation services and to replace certain existing facilities. The Eastern Market Expansion is projected to add 97,000 Dth per day of storage and transportation deliverability and is fully subscribed on a 15-year contracted firm basis. Construction of the facilities is complete and the project was placed in service April 1, 2009.

Appalachian Expansion Project. On August 22, 2008, the FERC issued an order to Columbia Transmission, which granted a certificate to construct the project. The project includes building a new 9,470 hp compressor station in West Virginia. The Appalachian Expansion Project will add 100,000 Dth per day of transportation capacity and is fully subscribed on a 15-year contracted firm basis. Construction is in progress and the project is expected to be in service by the second half of 2009.

Ohio Storage Project. On June 24, 2008, Columbia Transmission filed an application before the FERC for approval to expand two of its Ohio storage fields for additional capacity of nearly 7 Bcf and 103,400 Dth per day of daily deliverability. Approval was granted in March 2009 and construction of the facilities began in April 2009. Partial service related to this expansion is expected to be available by May 1, 2009 and the remainder will be

ITEM 1. FINANCIAL STATEMENTS (continued)

available no later than the fourth quarter of 2009. The expansion capacity is 58% contracted on a long-term, firm basis with revenue based on market-based rates recently approved by the FERC.

Electric Operations Regulatory Matters

Significant Rate Developments. Northern Indiana filed a petition for new electric base rates and charges on June 27, 2008. The case-in-chief was originally filed on August 29, 2008, and amended on December 19, 2008 after the Sugar Creek facility was successfully dispatched into MISO. The filing requests an increase in base rates calculated to produce additional annual gross margin of $85.7 million annually. Evidentiary hearings on Northern Indiana’s direct case commenced on January 12, 2009 and concluded on February 6, 2009. Several stakeholder groups have intervened in the case, representing customer groups and various counties and towns within Northern Indiana’s electric service territory. A field hearing to record customer testimony was held on March 3, 2009. The OUCC and intervenors are scheduled to file their cases-in-chief in May 2009. Northern Indiana is scheduled to file its rebuttal testimony in June 2009, and final hearings are planned to begin July 27, 2009. If a settlement agreement is not reached, and the full procedural schedule takes place, it is anticipated that new rates would take effect in early 2010.

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 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 enters a base rate order that approves revised Northern Indiana electric rates. The order included a rate moratorium that expired on July 31, 2006. The order also provides that 60% of any future earnings beyond a specified earnings level will be retained by Northern Indiana. The revenue credit is calculated based on electric usage; therefore, in times of high usage the credit may be more than $55.1 million. Credits amounting to $13.2 million and $12.5 million were recognized for electric customers for the first quarters of 2009 and 2008, respectively.

MISO. As part of Northern Indiana’s participation in the MISO transmission service and wholesale energy market, 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 the administrative fees and certain non-fuel related costs incurred after Northern Indiana’s rate moratorium, which expired on July 31, 2006. During the first quarter of 2009, non-fuel costs credits of $3.0 million were deferred in accordance with the aforementioned orders. In addition, administrative, FERC and other fees of $2.1 million were deferred. In total, for the first quarter of 2009 and 2008, net MISO credits of $0.9 million and costs of $0.9 million, respectively, were deferred. In the base rate case filed in August 2008, Northern Indiana proposed recovery over a three year amortization period of the cumulative amount of charges that will have been deferred by the time a rate order is issued, and a tracker for recovery of these charges on an ongoing basis. As noted below, as part of MISO’s initiation of an ASM, Northern Indiana will also incur non-fuel administrative costs associated with this market. The IURC authorized Northern Indiana to defer the costs associated with participating in the ASM subject to a final determination in a subsequent phase of the same proceeding. The IURC has not yet ruled in the subsequent phase of the ASM proceeding.

Northern Indiana is an active stakeholder in the process used in designing, testing and implementing the ASM and in developing the surrounding business practices. On January 18, 2008, Northern Indiana as part of a Joint Petition among several other Indiana utilities, “Joint Petitioners,” filed a request to the IURC to participate in ASM and seek approval of timely cost recovery for the associated costs of participating. On August 13, 2008, the IURC issued a Phase I order, authorizing the Joint Petitioners authority to transfer additional balancing authority functions and to implement the operational changes necessary to participate in the ASM and to seek recovery of modified MISO charge-types via the FAC and to defer certain other MISO charge-types, pending a final determination on the issue of cost recovery in Phase II. This order also created a subdocket for the purpose of further consideration of whether a cost-benefit analysis of participation in MISO or the MISO ASM should be required. Phase II of this proceeding deals with how the Joint Petitioners will approach the ASM, specifically related to cost recovery. The evidentiary hearing for Phase II concluded on February 9, 2009. The market began on January 6, 2009. At this time, Northern Indiana is not yet able to determine what impact the ASM will have on its cash flows.

On November 7, 2008, the FERC issued an order regarding the clarification of a rate mismatch as it pertains to the RSG First Pass calculation. On November 10, 2008, the FERC issued an order indicating that the RSG rates in

ITEM 1. FINANCIAL STATEMENTS (continued)

effect were unjust and unreasonable based on a Section 206 filing that Northern Indiana and Ameren Services Company jointly filed on August, 10, 2007. MISO determined that resettlements are required for all periods from market start to the Section 206 Refund effective date to remedy the rate mismatch. The FERC ordered refunds with interest after August 10, 2007. MISO, in its compliance filing, indicated it will perform another resettlement to recalculate the RSG First Pass Distribution Rate. These resettlements began on March 6, 2009 and will conclude by the first quarter of 2010. As the result of these resettlements, Northern Indiana will see a shift from RSG Second Pass, which is a non fuel charge, as determined from a previous IURC order, to the RSG First Pass Distribution, which is included as part of the fuel cost mechanism. The interim RSG allocation is still subject to rehearing. Northern Indiana does not expect a material impact on the financial statements.

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 intervenors, including the OUCC, have 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 - December 2008. The IURC has granted a sub-docket to consider such issues in those filings. The intervening parties and Northern Indiana are discussing procedures to eliminate these concerns and to resolve them for the historical periods. There is no procedural schedule established for this sub-docket.

The IURC issued an order on May 28, 2008 approving the purchase of Sugar Creek, and on May 30, 2008 Northern Indiana purchased the 535 mw CCGT for $330 million in order to help meet capacity needs. The IURC, on February 18, 2009, issued an order approving a settlement agreement filed in this proceeding allowing Northern Indiana to begin deferring carrying costs and depreciation on Sugar Creek effective on December 1, 2008, when Sugar Creek was dispatched into MISO, at the agreed to carrying cost rate of 6.5%. The terms of recovery of the deferral will be resolved in Northern Indiana’s current rate proceeding. On March 19, 2009, LaPorte County filed a notice of appeal regarding the IURC’s decision.

As part of a settlement agreement which resolved issues surrounding purchased power costs, Northern Indiana implemented a new “benchmarking standard,” that became effective in October 2007, which defines the price above which purchased power costs must be absorbed by Northern Indiana and are not permitted to be passed on to ratepayers. The benchmark is based upon the costs of power generated by a hypothetical natural gas fired unit using gas purchased and delivered to Northern Indiana and a set sharing mechanism. During the first quarter of 2009 and 2008, the amount of purchased power costs exceeding the benchmark amounted to $0.8 million and $3.8 million, respectively, which was recognized as a net reduction of revenues. The agreement also contemplated Northern Indiana adding generating capacity to its existing portfolio by providing for the benchmark to be adjusted as new capacity is added. The dispatch of Sugar Creek into MISO on December 1, 2008 triggered a change in the benchmark, whereby the first 500 mw tier of the benchmark provision was eliminated.

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 through an ECRM and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational through an EERM. Under the IURC’s November 26, 2002 order, Northern Indiana is permitted to submit filings on a semi-annual basis for the ECRM and on an annual basis for the EERM. In addition, Northern Indiana received an IURC order issuing a CPCN for the CAIR and CAMR Phase I Compliance Plan Projects, estimated to cost approximately $23 million. Northern Indiana includes the CAIR and CAMR Phase I Compliance Plan costs to be recovered in the semi-annual ECRM and annual EERM filing six months after construction costs begin. On October 23, 2008, Northern Indiana filed for approval of a revised cost estimate to meet the NOx and SO2 and mercury emissions environmental standards. Northern Indiana anticipates a total capital investment of approximately $368 million. This revised cost estimate was approved by the IURC on January 14, 2009. On October 1, 2008, the IURC approved ECR-12 for capital expenditures (net of accumulated depreciation) of $267.7 million. Northern Indiana filed ECR-13 and EER-6 in February 2009, for net capital expenditures and expense of $268.1 million and $18.7 million, respectively. In the electric base rate case, Northern Indiana has proposed that the frequency of the EERM be changed from annual to semi-annual, consistent with the filing of the ECRM. In addition, Northern Indiana proposed that the EERM be used to pass through to ratepayers the cost of any emission allowance purchases and the proceeds of any emission allowance sales.

ITEM 1. FINANCIAL STATEMENTS (continued)

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. In accordance with SFAS No. 133, NiSource designates many 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 natural gas or power for its operational needs. These forward physical contracts are derivatives which qualify for the normal purchase normal sales exception under SFAS No. 133 and do not require mark-to-market accounting. NiSource adopted SFAS No. 161 on January 1, 2009, an amendment to SFAS No. 133, and the disclosures contained in this note regarding NiSource’s use of derivatives are pursuant to the requirement of SFAS No. 133, as amended.

Accounting Policy for Derivative Instruments. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities on the Consolidated Balance Sheets at fair value, unless such contracts are exempted such as a normal purchase normal sale contract under the provisions of the standard. 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 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 normal sale exemption under SFAS. No. 133, 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 accumulated other comprehensive income (loss), 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 accumulated other comprehensive income (loss) 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.

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 by economically hedging the various gas cost components by using a combination of futures,

ITEM 1. FINANCIAL STATEMENTS (continued)

options, forward physical contracts, basis swap contracts or other derivative contract. 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, Northern Indiana Fuel and Light, Kokomo Gas, 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’ gas cost recovery mechanism, regulatory assets or liabilities are recorded to offset the change in the fair value of these derivatives.

Northern Indiana, Columbia of Virginia and Columbia of Pennsylvania offer a fixed price program as an alternative to the standard gas cost recovery 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 normal sale exemption under SFAS No. 133 is elected for forward physical contracts associated with these programs whereby 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 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 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 normal sale exemption under SFAS No. 133 is elected for forward physical contracts associated with these programs whereby delivery of the commodity is probable to occur.

For regulatory incentive purposes, 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, in accordance with SFAS No. 71, Northern Indiana records the related gains and losses associated with these transactions as a regulatory asset or liability.

For regulatory incentive purposes, Columbia of Kentucky, Columbia of Ohio, Columbia of Pennsylvania, and Columbia of Maryland (collectively, the “Columbia LDCs”) enter into contracts that allow counterparties the option to sell gas to Columbia LDCs at first of the month prices for a particular month of delivery. 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 in accordance with SFAS No. 71 based on the regulatory customer sharing mechanisms in place, with the remaining changes in fair value recognized currently in earnings.

The operations of TPC primarily involve commercial and industrial gas sales, whereby TPC utilizes gas derivatives to hedge its expected future gas purchases. These derivatives associated with commercial and industrial gas sales are accounted for as cash flow hedges. TPC enters into forward physical sales contracts of natural gas with customers. These forward physical sales contracts are derivatives which qualify for, and for which TPC has elected, the normal purchase normal sales exception under SFAS No. 133 and do not require mark-to-market accounting.

As part of the MISO Day 2 initiative, Northern Indiana was allocated and 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 do not qualify for hedge accounting treatment, 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

ITEM 1. FINANCIAL STATEMENTS (continued)

regulatory asset or liability, in accordance with SFAS No. 71. 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. Northern Indiana converted the ARRs that were received in the second quarter of 2008 into FTRs.

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

		March 31, 2009			December 31, 2008
Commodity Price Risk Program:
Gas price volatility program derivatives (MMDth)			23.3				31.2
PPS program derivatives (MMDth)			2.0				1.9
DependaBill program derivatives (MMDth)			0.2				0.3
Regulatory incentive program derivatives (MMDth)			7.6				2.9
Gas marketing program derivatives (MMDth) (a)			78.3				84.4
Electric energy program FTR derivatives (mw)			4,408				8,068

(a)

Basis contract volumes were 80.3 (MMDth) and 83.5 (MMDth) as of March 31, 2009 and December 31, 2008, respectively.

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 Corp. 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 March 31, 2009, NiSource had $6.9 billion of outstanding debt, of which $1.1 billion 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. The effectiveness of the interest rate swaps in offsetting the exposure to changes in the debt’s fair value is measured pursuant to SFAS No. 133. NiSource had no net gain or loss recognized in earnings due to hedging ineffectiveness from prior years.

On May 12, 2004, NiSource Finance entered into fixed-to-variable interest rate swap agreements in a notional amount of $660 million with six counterparties having a 6 1/2-year term. NiSource Finance will receive payments based upon a fixed 7.875% interest rate and pay a floating interest amount based on U.S. 6-month BBA LIBOR plus an average of 3.08% 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 May 15, 2009. On September 15, 2008, NiSource Finance terminated a fixed-to-variable interest rate swap agreement with Lehman Brothers having a notional amount of $110 million.

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 will receive payments based upon a fixed 5.40% interest rate and pay 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.

As stated above, on September 15, 2008, NiSource Finance terminated a fixed-to-variable interest rate swap agreement with Lehman Brothers having a notional amount of $110 million. NiSource Finance elected to terminate the swap when Lehman Holdings Inc., guarantor under the applicable International Swaps and Derivatives Association agreement, filed for Chapter 11 bankruptcy protection on September 14, 2008, which constituted an event of default under the swap agreement between NiSource Finance and Lehman Brothers Special Financing Inc. The mark-to-market close-out value of this swap at the September 15, 2008 termination date was determined to be $4.8 million and was fully reserved in the third quarter of 2008. The termination of this swap did not impact NiSource’s ability to assert hedge accounting for its remaining fixed-to-variable interest rate swap agreements.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Contemporaneously with the issuance on September 16, 2005 of the 5.25% and 5.45% notes, 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 accumulated other comprehensive loss 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 March 31, 2009, $15.6 million is in accumulated other comprehensive loss related to forward starting interest rate swap settlement.

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

		Asset Derivatives										Liability Derivatives
				March 31,				December 31,						March 31,				December 31,
				2009				2008						2009				2008
(in millions)		Balance Sheet Location		Fair Value				Fair Value				Balance Sheet Location		Fair Value				Fair Value
Derivatives designated as hedging instruments under SFAS No. 133
Commodity price risk programs		Price risk management assets (current)		$	172.3			$	143.5			Price risk management liabilities (current)		$	285.3			$	233.6
		Price risk management assets (noncurrent)			111.6				104.9			Price risk management liabilities (noncurrent)		$	189.8				171.4
Interest rate risk activities		Price risk management assets (noncurrent)			92.6				95.8			Price risk management liabilities (noncurrent)			—				—
Total derivatives designated as hedging instruments under SFAS No. 133				$	376.5			$	344.2					$	475.1			$	405.0
Derivatives not designated as hedging instruments under SFAS No. 133
Commodity price risk programs		Price risk management assets (current)		$	1.2			$	6.9			Price risk management liabilities (current)		$	50.7			$	52.9
		Price risk management assets (noncurrent)			—				—			Price risk management liabilities (noncurrent)			5.6				17.1
Total derivatives not designated as hedging instruments under SFAS No. 133				$	1.2			$	6.9					$	56.3			$	70.0
Total Derivatives				$	377.7			$	351.1					$	531.4			$	475.0

The effect of derivative instruments on the Condensed Statement of Consolidated Income (unaudited) were:

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Three Months Ended, (in millions)

		Amount of Gain (Loss)										Amount of Gain (Loss)
		Recognized in OCI on										Reclassified from AOCI
		Derivative (Effective								Location of Gain (Loss)		into Income (Effective
Derivatives in SFAS No. 133		Portion)								Reclassified from AOCI		Portion)
Cash Flow Hedging		March 31,				March 31,				into Income (Effective		March 31,				March 31,
Relationships		2009				2008				Portion)		2009				2008
Commodity price risk programs		$	(14.9	)		$	16.9			Cost of Sales		$	(43.8	)		$	9.2
Interest rate risk activities			0.4				0.4			Interest expense, net			(0.4	)			(0.4	)
Total		$	(14.5	)		$	17.3					$	(44.2	)		$	8.8

Three Months Ended, (in millions)

				Amount of Gain (Loss) Recognized
		Location of Gain (Loss)		in Income of Derivative
		Recognized in Income on		(Ineffective Portion and Amount
		Derivative (Ineffective Portion		Excluded from Effectiveness
Derivatives in SFAS No. 133 Cash Flow		and Amount Excluded from		Testing)
Hedging Relationships		Effectivness Testing)		March 31, 2009				March 31, 2008
Commodity price risk programs		Cost of Sales		$	—			$	(0.1	)
Interest rate risk activities		Interest expense, net			—				—
Total				$	—			$	(0.1	)
During first quarter of 2009 and 2008, NiSource did not reclassify any amounts related to its cash flow hedges from accumulated other comprehensive loss to earnings due to the probability that certain forecasted transactions would not occur. 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 accumulated other comprehensive loss of approximately $79.3 million of loss, net of taxes.
Derivatives in Fair Value Hedging Relationships
Three Months Ended, (in millions)
				Amount of Gain (Loss) Recognized
Derivatives in SFAS No. 133 Fair		Location of Gain (Loss) Recognized in		in Income on Derivatives
Value Hedging Relationships		Income on Derivatives		March 31, 2009				March 31, 2008
Interest rate risk activites		Interest expense, net		$	7.1			$	0.3
Total				$	7.1			$	0.3
Three Months Ended, (in millions)
				Amount of Gain (Loss) Recognized
Hedged Item in SFAS No. 133		Location of Gain (Loss) Recognized in		in Income on Related Hedged Items
Fair Value Hedge Relationships		Income on Related Hedged Item		March 31, 2009				March 31, 2008
Fixed-rate debt		Interest expense, net		$	(7.1	)		$	(0.3	)
Total				$	(7.1	)		$	(0.3	)

ITEM 1. FINANCIAL STATEMENTS (continued)

Three Months Ended, (in millions)

				Amount of Realized/Unrealized Gain (Loss)
		Location of Gain		Recognized in Income on
Derivatives Not Designated		(Loss) Recognized in		Derivatives
as Hedging Instruments		Income on		March 31,				March 31,
under SFAS No. 133		Derivatives		2009				2008
Commodity price risk programs		Gas Distribution revenues			(61.2	)			(16.2	)
Commodity price risk programs		Cost of Sales			(1.9	)			0.2
Total					(63.1	)			(16.0	)

NiSource’s derivative instruments measured at fair value under SFAS No. 133 as of March 31, 2009 do not contain any credit-risk-related contingent features.

Certain NiSource affiliates have physical commodity purchase agreements that meet the definition of a derivative for which NiSource has elected the normal purchase normal sale exemption. These agreements are exempt from the requirement of SFAS No. 133 and are not measured at fair value. Certain of these agreements do 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 and Poor’s or below Baa3 by Moody’s. The collateral requirement from a downgrade for these normal purchase normal sale agreements below the ratings trigger levels would amount to approximately $1.9 million as of March 31, 2009.

NiSource had approximately $316.2 million and $285.5 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 March 31, 2009 and December 31, 2008, respectively.

Fair Value Measurements. NiSource adopted the provisions of SFAS No. 157 for financial assets and liabilities on January 1, 2008 and the effective date provision for non-financial assets and liabilities delayed by the issuance of FSP FAS 157-2 on January 1, 2009. There was no impact on retained earnings as a result of the adoption.

ITEM 1. FINANCIAL STATEMENTS (continued)

Recurring Fair Value Measurements. The following table presents financial assets and liabilities measured and recorded at fair value on NiSource’s Condensed Consolidated Balance Sheet (unaudited) on a recurring basis and their level within the fair value hierarchy as of March 31, 2009:

		Quoted Prices in				Significant
		Active Markets				Other				Significant
		for Identical				Observable				Unobservable
Recurring Fair Value Measurements		Assets				Inputs				Inputs				Balance as of
(in millions)		(Level 1)				(Level 2)				(Level 3)				March 31, 2009
Assets
Price risk management assets		$	274.4			$	102.3			$	1.0			$	377.7
Available-for-sale securities			28.6				39.6				—				68.2
Total		$	303.0			$	141.9			$	1.0			$	445.9
Liabilities
Price risk management liabilities		$	505.8			$	25.3			$	0.3			$	531.4
Total		$	505.8			$	25.3			$	0.3			$	531.4

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-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. The company 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.

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. Unrealized gains and losses from available-for-sale securities are included in other comprehensive income.

ITEM 1. FINANCIAL STATEMENTS (continued)

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the period ended March 31, 2009:

		Financial
(in millions)		Transmission Rights				Other Derivatives				Total
Balance as of January 1, 2009		$	2.6			$	1.6			$	4.2
Total gains or losses (unrealized/realized)
Included in regulatory assets/liabilities			—				0.2				0.2
Purchases, issuances and settlements (net)			(1.7	)			(2.0	)			(3.7	)
Balance as of March 31, 2009		$	0.9			$	(0.2	)		$	0.7
Change in unrealized gains/(losses) relating to instruments still held as of March 31, 2009		$	—			$	0.2			$	0.2

As part of the MISO Day 2 initiative, Northern Indiana was allocated and has purchased FTRs. These rights help Northern Indiana offset congestion costs due to the MISO Day 2 activity. These instruments are considered derivatives and are valued utilizing forecasted congestion source and sink prices in the Day Ahead market. They are classified as Level 3 and reflected in the table above. The FTRs do not qualify for hedge accounting treatment, 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 accordance with SFAS No. 71. Northern Indiana also writes options for regulatory incentive purposes which are also considered Level 3 valuations and accounted for in accordance with SFAS No. 71. 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 non-recurring fair value measurements in the quarter ended March 31, 2009.

11. Goodwill

NiSource’s goodwill at March 31, 2009 was $3,677.3 million pertaining primarily to the acquisition of Columbia on November 1, 2000. The goodwill balance also includes $13.3 million for Northern Indiana Fuel and Light and $5.5 million for Kokomo Gas.

NiSource’s last goodwill impairment test occurred at June 30, 2008 which indicated no impairment charge was required. NiSource continually monitors potential indicators of impairment to determine if any triggering events are present that would require an impairment test more frequently than the annual test. As of March 31, 2009, NiSource’s market capitalization was approximately $2.7 billion, while NiSource’s net assets, inclusive of goodwill, were $4.7 billion. NiSource’s market capitalization at June 30, 2008 of approximately $4.9 billion was above NiSource’s net asset value when the annual impairment test was performed. In accordance with paragraph 28 of SFAS No. 142, NiSource considered whether there were any events or changes in circumstances during the first quarter of 2009 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 which would require goodwill impairment testing during the first quarter.

NiSource attributes the decline in its market capitalization primarily to the overall stock market decline resulting from the credit crisis taking place in the United States and globally, and not any fundamental change in NiSource’s regulated gas distribution and gas transmission and storage businesses that comprise the reporting units for which goodwill is attributable. NiSource’s stock price declined 10.7% at March 31, 2009 as compared to December 31, 2008, performing slightly better than the Dow Jones Industrial Average and Dow Jones Utility Average which declined 13.3% and 11.2%, respectively, during the three-month period. Given the lack of fundamental changes in

ITEM 1. FINANCIAL STATEMENTS (continued)

the underlying businesses that carry goodwill, NiSource does not believe the decline in its stock price and the reasons for that decline are indicative of an actual decline in the company’s fair value of the assets.

NiSource’s reportable entities with goodwill consist of regulated companies. Regulated recovery rates and approved rate of returns allow for more predictable and steady streams of revenues and cash flows which help mitigate the impacts that might otherwise be felt from the recessionary trends seen in other industries and also adds more reliability to the cash flow forecasts used to calculate fair value. It should also be noted that NiSource has demonstrated the ability to obtain credit. In the first quarter of 2009, NiSource was able to issue debt and address most of its liquidity needs for the current year, further indicating there is no fundamental issue with the underlying businesses. Refer to Note 14, “Long-Term Debt,” for discussion on the issuance of long-term debt during the quarter.

12. Income Taxes

NiSource’s interim effective tax rates reflect the estimated annual effective tax rates for 2009 and 2008, respectively, adjusted for tax expense associated with certain discrete items. The effective tax rates for the quarter ended March 31, 2009 and March 31, 2008 were 38.0% and 37.2%, 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.

The 0.8% increase in the effective tax rate in the first quarter of 2009 versus the first quarter of 2008 is due primarily to a reduction in estimated Section 199 deductions as a result of lower projected taxable income for 2009, and an increase in tax expense related to AFUDC-Equity and certain depreciation differences. Both periods included adjustments for discrete items which increased tax expense by $1.9 million in the first quarter of 2009 and $2.2 million in the first quarter of 2008.

On March 31, 2008, the governor of West Virginia signed legislation that phases in a reduction in income tax rates from the then current rate of 8.75% to 6.5% over the years 2009 through 2014. The 8.5% West Virginia tax rate that became effective on January 1, 2009 is reflected in current period income tax expense.

On July 3, 2008, the Governor of Massachusetts signed into law a bill that significantly changed the Massachusetts corporate income tax regime. Under the new law, which became effective for tax years beginning on or after January 1, 2009, NiSource calculates its Massachusetts income tax liability on a unitary basis, meaning that the income tax obligation to the Commonwealth of Massachusetts is determined based on an apportioned share of all of NiSource’s income, rather than just the income of NiSource’s subsidiaries doing business in Massachusetts. Because of NiSource’s substantial operations outside of Massachusetts, the new law had the impact of reducing the deferred income tax liability to Massachusetts. In accordance with SFAS No. 109, NiSource recognized the impact of this tax law change in the third quarter of 2008. First quarter 2009 income tax expense reflects the impact of the new law on a going forward basis.

There have been no material changes in 2009 to NiSource’s FIN 48 liabilities since December 31, 2008.

13. Pension and Other Postretirement Benefits

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.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource expects to make contributions of approximately $104.2 million to its pension plans and approximately $52.9 million to its postretirement medical and life plans in 2009, which could change depending on market conditions. Through March 31, 2009, NiSource has contributed $4.9 million to its pension plans and $11.9 million to its other postretirement benefit plans.

The following table provides the components of the plans’ net periodic benefits cost for the first quarter of 2009 and 2008:

		Pension Benefits								Other Postretirement Benefits
Three Months Ended March 31, (in millions)		2009				2008				2009				2008
Components of Net Periodic Benefit Cost
Service cost		$	9.0			$	9.3			$	2.2			$	2.4
Interest cost			35.8				33.1				11.9				11.9
Expected return on assets			(30.5	)			(48.5	)			(4.2	)			(6.3	)
Amortization of transitional obligation			—				—				2.0				2.0
Amortization of prior service cost			1.0				1.1				0.3				0.2
Recognized actuarial loss			16.4				0.3				1.9				1.0
Total Net Periodic Benefits Cost		$	31.7			$	(4.7	)		$	14.1			$	11.2

The significant increase in pension cost for 2009 is due to a $797.7 million, or 35.6%, reduction in pension plan assets in 2008 due to a 30.3% negative return on assets for the year resulting from the overall market decline and benefit payments of $165.9 million made during 2008. For the quarters ended March 31, 2009 and 2008, pension and other postretirement benefit cost of approximately $12.3 million and income of $1.1 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.

14. Long-Term Debt

On March 31, 2009, NiSource Finance announced that it was commencing a cash tender offer for up to $300 million aggregate principal amount of its outstanding 7.875% Notes due 2010. The aggregate principal amount of notes tendered on April 28, 2009 was approximately $250.6 million.

On March 9, 2009, NiSource Finance issued $600.0 million of 10.75% unsecured notes that mature March 15, 2016.

During February 2009, NiSource negotiated a two-year bank term loan with a syndicate of banks maturing in February 2011. Borrowings under the term loan have an effective cost of LIBOR plus 538 basis points. The initial closing occurred on February 13, 2009 under which NiSource received bank commitments of $265 million. The final closing occurred on April 9, 2009 with aggregate funding totaling $385 million. The new term loan matures on February 11, 2011.

During January 2009, NiSource repurchased $32.4 million of the $450.0 million floating rate notes scheduled to mature in November 2009 and $67.6 million of the $1.0 billion 7.875% unsecured notes scheduled to mature in November 2010.

NiSource currently issues 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.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

At March 31, 2009, there were 27,207,605 shares reserved for future awards under the amended and restated 1994 Plan.

NiSource recognized stock-based employee compensation expense of $1.6 million and related tax benefits of $0.6 million during the first three months of both 2009 and 2008.

As of March 31, 2009, the total remaining unrecognized compensation cost related to nonvested awards amounted to $19.9 million, which will be amortized over the weighted-average remaining requisite service period of 2.3 years.

Stock Options. As of March 31, 2009, approximately 4.7 million options were outstanding and exercisable with a weighted average option price of $22.62.

Restricted Awards. On March 24, 2009, 308,496 restricted stock units subject to service conditions were granted. The grant date fair-value of the restricted units was $3.0 million, based on the average market price of NiSource’s common stock at the date of grant of $10.15, which will be expensed net of forfeitures ratably over the three year requisite service period. The service conditions lapse on January 31, 2012 when 100% of the shares vest. If the employee terminates employment before January 31, 2012 (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. As of March 31, 2009, 541,304 nonvested restricted stock units were granted and outstanding.

Contingent Stock Units. On March 24, 2009, 925,490 contingent stock units subject to performance conditions were granted. The grant date fair-value of the award was $9.1 million, based on the average market price of NiSource’s common stock at the date of grant of $10.15 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: cumulative net operating earnings, that NiSource defines as income from continuing operations adjusted for certain items; cumulative funds from operations that NiSource defines as net operating cash flows provided by continuing operations; and total debt that NiSource defines as total debt adjusted for significant movement in natural gas prices and other adjustments determined by the Board. The service conditions lapse on January 31, 2012 when 100% of the shares vest. If the employee terminates employment before January 31, 2012 (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 March 31, 2009, 1,700,485 nonvested contingent stock units were granted and outstanding.

Time-accelerated Awards. NiSource awarded restricted shares and restricted stock units that contain provisions for time-accelerated vesting to key executives under the 1994 Plan in January 2004. The total shareholder return measures established were not met; therefore these grants do not have an accelerated vesting period. At March 31, 2009, NiSource had 276,614 awards outstanding which contained the time-accelerated provisions.

Non-employee Director Awards. The Amended and Restated Non-employee Director Stock Incentive Plan provides for awards of restricted stock, stock options and restricted stock units, which vest in 20% increments per year, with full vesting after five years. Effective March 25, 2008, the Board approved an amendment to the vesting provisions of the plan such that all outstanding grants and future grants of restricted stock units will vest immediately. The plan requires that restricted stock units be distributed to the directors after their separation from the Board. As of March 31, 2009, 89,860 restricted shares and 251,992 restricted stock units had been issued under the Plan.

16. Other Commitments and Contingencies

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.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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 March 31, 2009 and the years in which they expire were:

(in millions)		Total				2009				2010				2011				2012				2013				After
Guarantees of subsidiaries debt		$	6,314.0			$	427.6			$	932.4			$	—			$	315.0			$	545.0			$	4,094.0
Guarantees supporting commodity transactions of subsidiaries			460.9				280.2				176.3				—				—				—				4.4
Letters of credit			290.3				11.0				263.9				14.4				—				—				1.0
Other guarantees			841.6				61.7				2.9				—				15.6				225.4				536.0
Total commercial commitments		$	7,906.8			$	780.5			$	1,375.5			$	14.4			$	330.6			$	770.4			$	4,635.4

Guarantees of Subsidiaries Debt. NiSource has guaranteed the payment of $6.3 billion of debt for various wholly-owned subsidiaries including NiSource Finance, and through a support agreement, Capital Markets, which is reflected on NiSource’s Condensed Consolidated Balance Sheet (unaudited) as of March 31, 2009. The subsidiaries are required to comply with certain financial covenants under the debt instruments 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.

Guarantees Supporting Commodity Transactions of Subsidiaries. NiSource has issued guarantees, which support up to approximately $460.9 million of commodity-related payments for its current subsidiaries involved in energy marketing and trading and those satisfying requirements under forward gas sales agreements of current and former subsidiaries. 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).

Lines and Letters of Credit. NiSource Finance maintains a $1.5 billion five-year revolving credit facility with a syndicate of banks which has a termination date of July 7, 2011. This facility provides a reasonable cushion of short-term liquidity for general corporate purposes including meeting cash requirements driven by volatility in natural gas prices, as well as provides for the issuance of letters of credit. During September 2008, NiSource Finance entered into a new $500 million six-month revolving credit agreement with a syndicate of banks led by Barclays Capital that was originally due to expire on March 23, 2009. However, on February 13, 2009, the six-month credit facility was terminated in conjunction with the closing of a new two-year bank term loan. At March 31, 2009, NiSource had no short-term borrowings outstanding under its credit facility and has issued stand-by letters of credit of approximately $290.3 million for the benefit of third parties.

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 March 31, 2009.

NiSource has additional purchase and sales agreement guarantees totaling $77.5 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 Consolidated Balance Sheets. 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.

On August 29, 2007, Millennium entered into a bank credit agreement to finance the construction of the Millennium pipeline project. As a condition precedent to the credit agreement, NiSource issued a guarantee securing payment for 47.5%, its indirect ownership interest percentage, of amounts borrowed under the credit agreement up until such time as the amounts payable under the agreement are paid in full. As of March 31, 2009, Millennium owed $798.9

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

million under the financing agreements, of which NiSource guaranteed $379.5 million. NiSource recorded an accrued liability of approximately $7.6 million related to the fair value of this guarantee. The permanent financing for Millennium is expected to be completed when debt capital market conditions improve. In the interim, Millennium will continue to be funded by the $800 million credit agreement, which extends through August 2010.

On June 29, 2006, Columbia Transmission, Piedmont, and Hardy Storage entered into multiple agreements to finance the construction of the Hardy Storage project, which is accounted for by NiSource as an equity investment. Under the financing agreement, Columbia Transmission issued guarantees securing payment for 50% of any amounts issued in connection with Hardy Storage up until such time as the project is placed in service and operated within certain specified parameters. As of March 31, 2009, Hardy Storage owed $123.4 million under the financing agreement, for which Columbia Transmission recorded an accrued liability of approximately $1.2 million related to the fair value of its guarantee securing payment for $61.7 million which is 50% of the amount borrowed.

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 adverse impact on NiSource’s consolidated financial position.

In the case of Tawney, et al. v. Columbia Natural Resources, Inc., the Plaintiffs, who are West Virginia landowners, filed a lawsuit in early 2003 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. In December 2004, the court granted plaintiffs’ motion to add NiSource and Columbia as defendants. Plaintiffs also claimed that the defendants fraudulently concealed the deduction of post-production charges. The court 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. All claims by the government of the United States are excluded from the class. Although NiSource sold CNR in 2003, NiSource remains obligated to manage this litigation and for the majority of any damages ultimately awarded to the plaintiffs. On January 27, 2007, the jury hearing the case returned a verdict against all defendants in the amount of $404.3 million; this is comprised of $134.3 million in compensatory damages and $270 million in punitive damages. In January 2008, the Defendants filed their petition for appeal, and on March 24, 2008, the Defendants filed their amended petition for appeal with the West Virginia Supreme Court of Appeals. On May 22, 2008, the West Virginia Supreme Court of Appeals refused the defendants petition for appeal. On August 22, 2008, Defendants filed their petitions to the United States Supreme Court for writ of certiorari. The Plaintiffs filed their response on September 22, 2008. On September 19, 2008, the West Virginia Supreme Court issued an order extending the stay of the judgment until proceedings before the United States Supreme Court are fully concluded. Given the West Virginia Court’s 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 West Virginia Circuit Court for Roane County, West Virginia, preliminarily approved a settlement agreement with a total settlement amount of $380 million. The settlement received final approval by the Court on November 22, 2008. NiSource’s share of the settlement liability is up to $338.8 million. NiSource has complied with its obligations under the settlement agreement to fund $85.5 million in the qualified settlement fund by January 13, 2009. Additionally, NiSource provided a letter of credit on January 13, 2009 in the amount of $254 million and thereby complied with its obligation to secure the unpaid portion of the settlement. The trial court entered its order discharging the judgment on January 20, 2009. The Court is supervising the administration of the settlement proceeds. NiSource will be required to make additional payments, pursuant to the settlement, upon notice from the Class Administrator.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

C. Environmental Matters.

General. The operations of NiSource are subject to extensive and evolving federal, state and local environmental laws and regulations intended to protect the public health and the environment. Such environmental laws and regulations affect operations as they relate to impacts on air, water and land.

A reserve of $81.6 million and $73.1 million has been recorded as of March 31, 2009 and December 31, 2008, respectively, to cover probable corrective actions at sites where NiSource has environmental remediation liability. Regulatory assets have been recorded to the extent environmental expenditures are expected to be recovered in rates. NiSource accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on many factors including currently enacted laws and regulations, existing technology and estimated site-specific costs whereby assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. NiSource’s estimated environmental remediation liability will be refined as events in the remediation process occur. Actual remediation costs may differ materially from NiSource’s estimates due to the dependence on the factors listed above.

Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called “greenhouse gases” such as carbon dioxide, a by-product of burning fossil fuels, and methane, a component of natural gas. Certain NiSource affiliates engage in efforts to voluntarily report and reduce their greenhouse gas emissions. On April 2, 2007, in Massachusetts v. EPA, the Supreme Court ruled that the EPA does have authority under the CAA to regulate emissions of greenhouse gases if it is determined that greenhouse gases have a negative impact on human health or the environment. On April 17, 2009, the EPA issued a proposed rule, which would make the following findings: (a) that greenhouse gases in the atmosphere endanger the public health and welfare within the meaning of the CAA and (b) that emissions of carbon dioxide and other greenhouse gases from new motor vehicles contribute to the mix of greenhouse gases in the atmosphere. The EPA is soliciting public comments on this new rule, which could become final in 2009. Although the EPA’s proposed findings deal only with new motor vehicles, the proposed rule could be a precursor for the regulation of other greenhouse gas sources by the EPA under the CAA. In addition, draft legislation has been developed in both the U.S. House of Representatives and the U.S. Senate. NiSource will continue to monitor and participate in developments related to efforts to potentially regulate greenhouse gas emissions.

The EPA proposed a mandatory greenhouse gas reporting rule on March 10, 2009, that would require reporting of greenhouse gas emissions from large sources. The emission information collected would be used by the EPA to develop comprehensive and accurate data relevant to future climate policy decisions, including potential future regulation of greenhouse gases. According to the proposal, data collection would begin January 1, 2010, with first reports due to the EPA on March 31, 2011. NiSource will continue to monitor development of this rule.

On February 25, 2009, the EPA proposed national emission standards for hazardous air pollutants for stationary reciprocating internal combustion engines that are not already covered by earlier EPA regulation. The proposed rule would impact smaller engines and impose a variety of additional requirements depending on the size and type of engine. In accordance with a consent decree, the proposed rule is scheduled to be finalized by February 10, 2010, with compliance generally required three years later. NiSource will continue to closely monitor developments in this matter and cannot estimate the cost of compliance at this time.

Implementation of the ozone and fine particulate matter NAAQS may require imposition of additional controls on boilers, engines and turbines. On April 15, 2004, the EPA finalized the eight-hour ozone nonattainment area designations under the 1997 eight-hour ozone NAAQS. After designation, the CAA provides for a process for promulgation of rules specifying compliance level, compliance deadline, and necessary controls to be implemented within designated areas over the next few years. In addition, on March 12, 2008, the EPA announced the tightening of the eight-hour ozone NAAQS. The number of areas that do not meet the new standard could significantly increase across the country, thus requiring additional federal and state attainment planning and rulemaking. Resulting federal and state rules could require additional reductions in NOx emissions from facilities owned by electric generation and gas transmission and storage operations.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

On March 29, 2007, the EPA signed a rule to govern implementation of the NAAQS for particulate matter (PM-2.5) that the EPA promulgated in 1997. The rule addresses a wide range of issues, including state rulemaking requirements as well as attainment demonstration requirements and deadlines. States must evaluate potential reduction measures for the emission of particulate matter and its precursors such as SO2 and NOx. The rule includes a conditional presumption that, for power plants subject to the CAIR, compliance with CAIR would satisfy Reasonably Available Control Measures and Reasonably Available Control Technology requirements for SO2 and NOx. States were required to submit attainment SIPs in April 2008. Also, on September 21, 2006, the EPA issued revisions to the NAAQS for particulate matter. The final rule increased the stringency of the current fine particulate (PM2.5) standard, added a new standard for inhalable coarse particulate (particulate matter between 10 and 2.5 microns in diameter), and revoked the annual PM10 standards while retaining the 24-hour PM10 standards. The EPA rule designating areas not meeting the new fine particulate matter standards was signed December 22, 2008, and expected to be effective in 2009. The SIPs detailing how states will reduce emissions to meet the NAAQS will be due three years later in order to meet attainment by 2014 with a possible five year extension to 2019. On February 24, 2009, the D.C. Circuit struck down the primary annual and secondary PM2.5 NAAQS promulgated by the EPA in 2006 (American Farm Bureau Federation, et al. v. EPA). These standards have been remanded to the EPA for reconsideration. The court denied the petitions to review the primary daily and annual standards for PM10. These standards are not vacated (i.e., they are still in effect, but must be reconsidered by the EPA). These actions could require further reductions in NOx emissions from various emission sources in and near nonattainment areas, including reductions from Gas Transmission and Storage Operations. NiSource will continue to closely monitor developments in these matters and cannot estimate the timing or cost of emission controls at this time.

Gas Distribution Operations. Several Gas Distribution Operations subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws, as well as at MGP sites, which such subsidiaries, or their corporate predecessors, own or previously owned or operated. Gas Distribution Operations subsidiaries may be required to share in the cost of cleanup of such sites. In addition, some Gas Distribution Operations subsidiaries have responsibility for corrective action under the RCRA for closure and cleanup costs associated with underground storage tanks and under the Toxic Substances Control Act for cleanup of PCBs. The final costs of cleanup have not yet been determined. As site investigations and cleanup proceed and as additional information becomes available reserves are adjusted.

A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors are the current or former owner. The program has identified up to 84 such sites and initial investigations have been conducted at 52 sites. Additional investigation activities have been completed or are in progress at 50 sites and remedial measures have been implemented or completed at 30 sites. This effort includes the sites contained in the January 2004 Indiana Voluntary Remediation Program agreements between the IDEM and Northern Indiana, Kokomo Gas, and other Indiana utilities. Only those site investigation, characterization and remediation costs currently known and determinable can be considered “probable and reasonably estimable” under SFAS No. 5. As costs become probable and reasonably estimable, reserves will be adjusted. As reserves are recorded, regulatory assets are recorded to the extent environmental expenditures are expected to be recovered through rates. NiSource is unable, at this time, to estimate the time frame and potential costs of the entire program. Management expects that, as characterization is completed, additional remediation work is performed and more facts become available, NiSource will be able to develop a probable and reasonable estimate for the entire program or a major portion thereof consistent with the SEC’s SAB No. 92, SFAS No. 5 and SOP 96-1.

Gas Transmission and Storage Operations. Columbia Transmission continues to conduct characterization and remediation activities at specific sites under a 1995 EPA AOC. The 1995 AOC covered 245 facilities, approximately 13,000 liquid removal points, approximately 2,200 mercury measurement stations and about 3,700 storage well locations. Field characterization has been performed at all sites. Site characterization reports and remediation plans, which must be submitted to the EPA for approval, are in various stages of development and completion. Remediation has been completed at the mercury measurement stations, liquid removal point sites, storage well locations and all but 48 of the 245 facilities. The AOC was amended in 2008 to facilitate payment of EPA oversight costs and to remove all but the remaining 48 facilities from the AOC.

Columbia Transmission and Columbia Gulf are potentially responsible parties at several waste disposal sites under CERCLA and similar state laws. The potential liability is believed to be de minimis. However, the final allocation

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

of cleanup costs has yet to be determined. As site investigations and cleanups proceed and as additional information becomes available reserves will be adjusted.

On February 21, 2007, PADEP provided representatives of Columbia Transmission with a proposed Consent Order and Agreement covering an unmanned equipment storage site located in rural southwest Pennsylvania. PADEP’s proposed order alleges that Columbia Transmission has violated the state’s Clean Streams Act and Solid Waste Management Act by discharging petroleum products onto the property and into the waters of the state. In addition to requiring remediation and monitoring activities at the site, the state has proposed penalties for these violations. The site was remediated via an EPA approved Remedial Action Work Plan in the summer of 2008. The PADEP had provided written notification that it would not attempt to stop the EPA approved work and would seek the aforementioned Order after the remedy is completed. On January 6, 2009, PADEP provided Columbia Transmission with a Consent Assessment of Civil Penalty seeking a civil penalty of $700 thousand for alleged violations of the Clean Streams Law. On April 23, 2009, PADEP sent Columbia Transmission an NOV. This NOV alleged the same violations as the January 6, 2009 Consent Assessment of Civil Penalty, but it also included violations of the Clean Streams Law that had allegedly been observed during a February 16, 2009 site inspection. The NOV increased the amount of PADEP’s settlement demand to $1 million. Columbia intends to seek clarification from PADEP regarding the proposed penalty.

Electric Operations.

Air. In December 2001, the EPA approved regulations developed by the State of Indiana to comply with the EPA’s NOx SIP call. The NOx SIP call requires certain states, including Indiana, to reduce NOx levels from several sources, including industrial and utility boilers, to lower regional transport of ozone. Compliance with the NOx limits contained in these rules was required by May 31, 2004. To comply with the rule, Northern Indiana developed a NOx compliance plan, which included the installation of Selective Catalytic Reduction and combustion control NOx reduction technology at its active generating stations and is currently in compliance with the NOx requirements. In implementing the NOx compliance plan, Northern Indiana has expended approximately $315.3 million as of March 31, 2009.

Implementation of the fine particulate matter and ozone NAAQS has the potential to require imposition of additional controls on coal-fired boilers. On April 15, 2004, the EPA finalized the eight-hour ozone nonattainment area designations for the 1997 eight-hour ozone NAAQS and designated Lake, Porter, and LaPorte counties as nonattainment of the standard. This triggered a multi-year process for development of rules specifying compliance level, compliance deadline, and necessary controls to be implemented within nonattainment areas. Local ozone air quality improved in these three counties, and LaPorte County was redesignated to attainment of the eight-hour ozone NAAQS effective January 28, 2008. IDEM is also recommending Lake and Porter counties be redesignated to attainment with the 1997 standard because of improved air quality during the most recent averaging period. However, the March 12, 2008 EPA tightening of the eight-hour ozone NAAQS may result in Lake, Porter and LaPorte counties again being designated as nonattainment of the new 2008 ozone NAAQS. As discussed above under “General,” the EPA ozone NAAQS revision could lead to additional emission reductions of NOx, an ozone precursor, from facilities owned by Northern Indiana. Northern Indiana will closely monitor developments in these matters and cannot at this time estimate the timing or cost of emission controls that may eventually be required.

Also, in 2005 Lake and Porter counties were designated nonattainment for fine particulate matter. Similar to ozone, local particulate matter air quality improved and IDEM submitted an attainment SIP that is awaiting EPA approval. Northern Indiana will continue to closely monitor developments in these matters and cannot predict the outcome or impact of the EPA action at this time.

On September 21, 2006, the EPA issued revisions to the NAAQS for particulate matter. The EPA rule designating areas not meeting the new (2006) fine particulate matter standards was signed December 22, 2008, and expected to be effective in 2009. The SIPs detailing how states will reduce emissions to meet the NAAQS in these areas will be due three years later with attainment due by 2014 and a possible five year extension to 2019. The SIPs developed to meet this standard could impact the emission control requirements for coal-fired boilers including Northern Indiana’s electric generating stations. Northern Indiana will continue to closely monitor developments in these matters and cannot estimate the impact, timing or cost of emission controls at this time.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

On October 15, 2008, the EPA announced its first strengthening of the NAAQS for lead in 30 years by tightening the standards from the current 1.5 micrograms per cubic meter to 0.15 micrograms per cubic meter and changing both the calculation method and averaging time. Also included are provisions for the EPA to improve the existing lead monitoring network by requiring placement of monitors in areas with industrial facilities that emit one or more tons per year of lead. Designations of whether or not areas meet the standards are to be finalized by January 2012 with the state plans for reducing emissions to meet the standards due in June 2013 and compliance by January 2017. Northern Indiana is unable to predict the outcome of this action at this time.

On March 10, 2005, the EPA issued the CAIR final regulations. The rule establishes phased reductions of NOx and SO2 from 28 Eastern states, including electric utilities in Indiana, by establishing an annual emissions cap for NOx and SO2 and an additional cap on NOx emissions during the ozone control season. On March 15, 2006, the EPA signed three related rulemakings providing final regulatory decisions on implementing the CAIR. The EPA, in one of the rulings, denied several petitions for reconsideration of various aspects of the CAIR, including requests by Northern Indiana to reconsider SO2 and NOx allocations. As an affected state, Indiana structured, and preliminarily adopted in June 2006, a draft rule to meet the EPA abbreviated CAIR SIP requirements and adopted the final rules on November 1, 2006. The CAIR rules became effective in Indiana on February 25, 2007. In a petition filed with the IURC in December 2006, Northern Indiana provided plans for the first phase of the emission control construction required to address the Phase I CAIR requirements and a request for appropriate cost treatment and recovery. Northern Indiana’s plan includes the upgrade of existing emission controls on three generating units for an estimated cost of $45.4 million and anticipates that these expenses are recoverable.

On July 11, 2008, the court vacated the CAIR in its entirety, and remanded the rule back to the EPA to develop a rule consistent with the court’s opinion. On September 24, 2008, four petitions were submitted seeking rehearing by the original panel and the full panel (en banc). Among the petitioners were the EPA as well as industry and environmental groups. On December 23, 2008, the court decided to remand the CAIR without vacatur to EPA in order to remedy the CAIR’s flaws in accordance with the court’s July 11, 2008 opinion in this case. Consequently, the federal CAIR remains in effect. Northern Indiana will continue to monitor this matter and can not predict the outcome or impact of EPA action at this time.

In anticipation of the issuance of the Court’s mandate to vacate CAIR upon the conclusion of legal proceedings, on October 23, 2008, the IDEM took the initial step to develop a new state rule to replace CAIR and obtain the emission reductions it would have achieved. As a result of the court’s December 23, 2008 action, the Indiana CAIR remains in effect and the IDEM suspended its replacement rulemaking activity. Northern Indiana will continue to monitor IDEM activity in this matter.

On October 3, 2007, the Indiana Air Pollution Control Board adopted, with minor changes from the EPA CAMR, the state rule to implement EPA’s CAMR. The rule became effective on February 3, 2008, with compliance required in 2010. On February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit vacated two EPA rules addressing utility mercury emissions that are the stimulus for the Indiana Air Pollution Control Board’s CAMR. The first is the EPA’s rule delisting coal and oil-fired electric generating units from the list of sources whose emissions are regulated under section 112 of the CAA, 42 U.S.C. § 7412. Revision of December 2000 Regulatory Finding (“Delisting Rule”), 70 Fed. Reg. 15,994 (March 29, 2005). The second is the EPA’s rule that set performance standards for new coal-fired electric generating units and established total mercury emission limits for states along with a cap-and-trade program for new and existing coal-fired electric generating units. Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units (“CAMR”), 70 Fed. Reg. 28,606 (May 18, 2005). In response to the vacatur, the EPA is pursuing a new Section 112 rulemaking to establish Maximum Achievable Control Technology standards for electric utilities. The EPA’s response to this decision will affect the implementation and timing of the installation of controls to address potential reduction obligations for mercury and other pollutants subject to the section 112 rulemaking. Northern Indiana will closely monitor developments regarding any further action by the EPA and subsequent regulatory developments from the EPA and/or the Indiana Air Pollution Control Board in this matter.

On October 3, 2007, the Indiana Air Pollution Control Board adopted, with some minor modifications, a rule to implement the EPA BART requirements for reduction of regional haze. The rule became effective February 22, 2008, with compliance with any required BART controls within five years (2013). The language of the final rule

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

relies upon the provisions of the Indiana CAIR to meet requirements for NOx and SO2 and does not impose any additional control requirements on coal-fired generation emissions, including those of Northern Indiana. As part of the BART analysis process, the IDEM evaluated the potential impact of particulate matter from electric generating units and found no significant impacts on Class I areas.

In late 1999, the EPA initiated a New Source Review enforcement action against several industries, including the electric utility industry, concerning rule interpretations that have been the subject of recent (prospective) reform regulations. Northern Indiana has received and responded to the EPA information requests on this subject, most recently in June 2002. The EPA issued an NOV to Northern Indiana on September 29, 2004, for alleged violations of the CAA and the SIP. Specifically, the NOV alleges that modifications were made to certain boiler units at the Michigan City, Schahfer, and Bailly Generating Stations between the years of 1985 and 1995 without obtaining appropriate air permits for the modifications. An adverse outcome in this matter could require capital expenditures beyond the EPA requirements that cannot be determined at this time and could require payment of substantial penalties.

Water. The Great Lakes Water Quality Initiative program added new water quality standards for facilities that discharge into the Great Lakes watershed, including Northern Indiana’s three electric generating stations located on Lake Michigan. The State of Indiana has promulgated its regulations for this water discharge permit program and has received final EPA approval. The NPDES water discharge permit for Michigan City Generating Station has been issued and became effective on April 1, 2006. Engineering studies have begun to determine specific compliance costs for this facility. The permit for the Bailly Generating Station was issued on June 26, 2006, and became effective on August 1, 2006. Northern Indiana appealed the Bailly Generating Station NPDES permit, due to an unacceptable internal outfall monitoring permit condition. On February 18, 2008, the Bailly Generating Station NPDES permit was modified to resolve the monitoring issue and to address the 316(b) rule status due to the remand mentioned below.

On February 16, 2004, the EPA Administrator signed the Phase II Rule of the Clean Water Act Section 316(b) which requires all large existing steam electric generating stations meet certain performance standards to reduce the effects on aquatic organisms at their cooling water intake structures. The rule 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. On January 25, 2007, the Second Circuit in a court decision on the Phase II 316(b) Rule, remanded for EPA reconsideration the options providing flexibility for meeting the requirements of the rule. On March 20, 2007, the EPA issued a guidance memo advising its Regional Administrators that the Agency considers the Phase II 316(b) Rule governing cooling water withdrawals suspended. On July 5, 2007, the Second Circuit Court of appeals denied the petitions for rehearing that had asked the court to reconsider its remand of the Phase II 316(b) Rule. On July 9, 2007, the EPA published a notice in the Federal Register suspending the Phase II Rule. The notice explained that the EPA is not accepting comments on the suspension and notes that “best professional judgment” is to be used in making 316(b) decisions.

Various parties submitted petitions for a writ of certiorari to the U.S. Supreme Court in early November 2007 seeking to reverse the Second Circuit Court’s decision. On April 1, 2009, the Supreme Court issued their ruling reversing and remanding the Second Circuit’s ruling. The case, Entergy Corp. v. Riverkeeper, Inc., determined that the EPA did not overstep its authority when it adopted national performance standards utilizing cost-benefit analyses. The matter will go back to the 2^nd Circuit U.S. Court of Appeals for further proceedings. The EPA will propose a revised 316(b) rule or provide guidance to address the impact of the court decision. Northern Indiana will continue to closely monitor this activity and cannot estimate the costs associated with the ultimate outcome at this time.

The IDEM issued a renewed NPDES Permit for Northern Indiana’s Michigan City Generating Station in 2006. The permit requires that the facility meet the Great Lakes Initiative discharge limits for copper. The Michigan City Generating Station originally had a four year compliance schedule to meet these limits, but on December 20, 2008, was granted a one year extension due to challenges with meeting the new limit. The new date of compliance with the new copper limits ends on April 2011 with the expiration of the current NPDES permit. Northern Indiana

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

currently is evaluating and implementing various alternatives for treating copper in wastewater at the Michigan City Generating Station.

Great Lakes Initiative-based discharge limits for mercury have also been set for both the Bailly and the Michigan City Generating Stations. Northern Indiana will collect data, develop and implement pollution reduction program plans, to demonstrate progress in reducing mercury discharge. Streamlined Mercury Variance applications will be submitted for both stations in 2009.

Remediation. Northern Indiana is a potentially responsible party under the CERCLA and similar state laws at two waste disposal sites and shares in the cost of their cleanup with other potentially responsible parties. At one site, the Remedial Investigation and Feasibility Study was submitted to the EPA in 2007. The EPA issued a Record of Decision in 2008 to conduct additional remedial activities at the site. At the second site, Northern Indiana has agreed to conduct a Remedial Investigation and Feasibility Study in the vicinity of the third party, state-permitted landfill where Northern Indiana contracted for fly ash disposal. In addition, Northern Indiana has corrective action liability under the RCRA for three facilities that historically stored hazardous waste.

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. A reserve has been established to fund the remedial measures proposed to the EPA. The final costs of cleanup could change based on EPA review.

On September 13, 2006, IDEM advised Northern Indiana that further investigation of historic releases from two previously removed underground storage tanks at the Schahfer Generating Station would need to be investigated. Northern Indiana completed an investigation of potentially impacted soils and groundwater and submitted results to the IDEM Leaking Underground Storage Tank section.

Coal Combustion Products. The Federal government continues to show interest in developing regulations covering coal combustion waste products. Subsequent to the December 22, 2008 dike collapse at a Tennessee Valley Authority ash pond, congressional hearings were held on the issue. Legislation regulating coal ash pursuant to the Surface Mining Control and Reclamation Act was introduced and the EPA is reviewing its previous determination that federal regulation of coal ash as a RCRA Subtitle C hazardous waste is not appropriate. Northern Indiana will monitor future regulatory actions and cannot estimate the potential financial impact at this time.

Renewable Portfolio Legislation. In 2009, the two Houses of the Indiana General Assembly passed different versions of a bill requiring electric utilities to implement a renewable portfolio standard. The versions are currently before a conference committee. If enacted, the renewable portfolio legislation would require Northern Indiana to obtain specified portions of its power from renewable sources by targeted dates. In addition to the Indiana legislation, Congress is considering legislation to create a Federal renewable portfolio standard. Either the Indiana or the Federal legislation could result in additional expense or compliance costs that may not be fully recoverable from customers and, as such, could materially impact Northern Indiana’s financial results. The cost impact of any new or amended legislation would depend upon the specific requirements enacted and cannot be determined at this time.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

17. Accumulated Other Comprehensive Loss

The following table displays the components of Accumulated Other Comprehensive Loss, which is included in “Common Stockholders’ Equity,” on the Condensed Consolidated Balance Sheets (unaudited).

		March 31,				December 31,
(in millions)		2009				2008
Other comprehensive loss, before taxes:
Unrealized (losses) gains on securities		$	(1.7	)			0.4
Tax benefit on unrealized gains on securities			0.8				—
Unrealized losses on cash flow hedges			(256.8	)			(232.1	)
Tax benefit on unrealized gains on cash flow hedges			102.5				92.3
Unrecognized pension benefit and OPEB costs			(51.8	)			(52.7	)
Tax benefit on unrecognized pension benefit and OPEB costs			19.8				20.1
Total Accumulated Other Comprehensive Loss, net of taxes		$	(187.2	)		$	(172.0	)

Millennium, in which Columbia Transmission has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420 million with seven counterparties. In accordance with paragraph 121 of SFAS No. 130, Columbia Transmission recorded an unrecognized loss of $24.8 million as a decrease in its investment in Millennium and a corresponding decrease in accumulated other comprehensive income, representing its ownership portion of the fair value of these swaps as of March 31, 2009.

18. Business Segment Information

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

NiSource’s operations are divided into four 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 and the District of Columbia. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana. The Other Operations segment primarily includes gas marketing, and ventures focused on distributed power generation technologies, including fuel cells and storage systems.

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.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Three Months Ended March 31, (in millions)		2009				2008
REVENUES
Gas Distribution Operations
Unaffiliated		$	1,947.6			$	2,439.1
Intersegment			5.7				7.1
Total			1,953.3				2,446.2
Gas Transmission and Storage Operations
Unaffiliated			182.2				168.3
Intersegment			60.1				63.0
Total			242.3				231.3
Electric Operations
Unaffiliated			298.2				332.8
Intersegment			0.2				0.2
Total			298.4				333.0
Other Operations
Unaffiliated			291.5				346.1
Intersegment			7.8				13.2
Total			299.3				359.3
Adjustments and eliminations			(73.1	)			(81.1	)
Consolidated Revenues		$	2,720.2			$	3,288.7
Operating Income (Loss)
Gas Distribution Operations		$	243.2			$	255.0
Gas Transmission and Storage Operations			92.9				104.8
Electric Operations			17.3				38.4
Other Operations			(1.4	)			(0.5	)
Corporate			(3.7	)			(2.8	)
Consolidated Operating Income		$	348.3			$	394.9