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

Commission file number 001-16189

(Exact name of registrant as specified in its charter)

		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)

(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 o    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		Smaller reporting company o
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes 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: 275,338,872 shares outstanding at July 31, 2009.

						Page
		Defined Terms					3
PART I		FINANCIAL INFORMATION					7
		Item 1.		Financial Statements - unaudited			7
				Condensed Statements of Consolidated Income (Loss) (unaudited)			7
				Condensed Consolidated Balance Sheets (unaudited)			8
				Condensed Statements of Consolidated Cash Flows (unaudited)			10
				Condensed Statements of Consolidated Comprehensive Income (Loss) (unaudited)			11
		Notes to Condensed Consolidated Financial Statements (unaudited)					12
		Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			50
		Item 3.		Quantitative and Qualitative Disclosures About Market Risk			85
		Item 4.		Controls and Procedures			85
PART II		OTHER INFORMATION					86
		Item 1.		Legal Proceedings			86
		Item 1A.		Risk Factors			88
		Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			89
		Item 3.		Defaults Upon Senior Securities			89
		Item 4.		Submission of Matters to a Vote of Security Holders			89
		Item 5.		Other Information			91
		Item 6.		Exhibits			91
		Signature					92
EX-31.1
EX-31.2
EX-32.1
EX-32.2

DEFINED TERMS

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

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
Northern Utilities		Northern Utilities, Inc.
NRC		NIPSCO Receivables Corporation
PEI		PEI Holdings, Inc.
Whiting Clean Energy		Whiting Clean Energy, Inc.
Abbreviations
AFUDC		Allowance for funds used during construction
Ameren		Ameren Services Company
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
CARE		Conservation and Ratemaking Efficiency
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

DEFINED TERMS (continued)

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
DOT		United States Department of Transportation
DSM		Demand Side Management
Dth		Dekatherm
EBITDA		Earnings Before Interest, Taxes, Depreciation and Amortization
ECR		Environmental Cost Recovery
ECRM		Environmental Cost Recovery Mechanism
ECT		Environmental cost tracker
EER		Environmental Expense Recovery
EERM		Environmental Expense Recovery Mechanism
EPA		United States Environmental Protection Agency
EPS		Earnings per share
FAC		Fuel adjustment clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
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
MMDth		Million dekatherms

DEFINED TERMS (continued)

mw		Megawatts
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NOx		Nitrogen oxide
NPDES		National Pollutant Discharge Elimination System
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income (Loss)
OPEB		Other postretirement benefits
OUCC		Indiana Office of Utility Consumer Counselor
PADEP		Pennsylvania Department of Environmental Protection
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. 131		Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information”
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”
SFAS No. 165		Statement of Financial Accounting Standards No. 165, “Subsequent Events”

DEFINED TERMS (continued)

SFAS No. 166		Statement of Financial Accounting Standards No. 166, “Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140”
SFAS No. 167		Statement of Financial Accounting Standards No. 167, “Amendments to FASB Interpretation No. 46(R)”
SFAS No. 168		Statement of Financial Accounting Standards No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB Statement No. 162”
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
VSCC		Virginia State Corporation Commission

ITEM 1.		FINANCIAL STATEMENTS

Condensed Statements of Consolidated Income (Loss) (unaudited)

		Three Months									Six Months
		Ended June 30,									Ended June 30,
(in millions, except per share amounts)		2009				2008					2009				2008
Net Revenues
Gas Distribution		$	448.8			$	928.1				$	2,171.7			$	3,164.9
Gas Transportation and Storage			260.9				236.1					657.5				594.3
Electric			285.4				339.9					582.2				671.7
Other			14.1				53.1					36.4				105.1
Gross Revenues			1,009.2				1,557.2					3,447.8				4,536.0
Cost of Sales (excluding depreciation and amortization)			338.2				892.0					1,713.1				2,833.8
Total Net Revenues			671.0				665.2					1,734.7				1,702.2
Operating Expenses
Operation and maintenance			363.7				343.5					841.8				752.9
Depreciation and amortization			148.2				147.6					291.9				283.1
Impairment and (gain)/loss on sale of assets, net			-				(0.9	)				(2.0	)			(2.4	)
Other taxes			52.6				62.2					154.7				164.3
Total Operating Expenses			564.5				552.4					1,286.4				1,197.9
Equity Earnings (Loss) in Unconsolidated Affiliates			(2.6	)			1.6					3.8				3.6
Operating Income			103.9				114.4					452.1				507.9
Other Income (Deductions)
Interest expense, net			(105.3	)			(87.4	)				(195.8	)			(179.2	)
Gain (Loss) on early extinguishment of long-term debt			(0.7	)			-					2.5				-
Other, net			(0.5	)			1.3					(4.7	)			(0.4	)
Total Other Income (Deductions)			(106.5	)			(86.1	)				(198.0	)			(179.6	)
Income (Loss) From Continuing Operations Before Income Taxes			(2.6	)			28.3					254.1				328.3
Income Taxes			6.1				8.6					103.5				120.0
Income (Loss) from Continuing Operations			(8.7	)			19.7					150.6				208.3
Income (Loss) from Discontinued Operations - net of taxes			12.7				(219.2	)				2.0				(212.4	)
Loss on Disposition of Discontinued Operations - net of taxes			(8.8	)			(2.8	)				(9.0	)			(98.9	)
Net Income (Loss)		$	(4.8	)		$	(202.3	)			$	143.6			$	(103.0	)
Basic Earnings (Loss) Per Share
Continuing operations		$	(0.03	)		$	0.07				$	0.55			$	0.76
Discontinued operations			0.01				(0.81	)				(0.03	)			(1.14	)
Basic Earnings (Loss) Per Share		$	(0.02	)		$	(0.74	)			$	0.52			$	(0.38	)
Diluted Earnings (Loss) Per Share
Continuing operations		$	(0.03	)		$	0.07				$	0.54			$	0.76
Discontinued operations			0.01				(0.80	)				(0.02	)			(1.13	)
Diluted Earnings (Loss) Per Share		$	(0.02	)		$	(0.73	)			$	0.52			$	(0.37	)
Dividends Declared Per Common Share		$	0.23			$	0.23				$	0.69			$	0.69
Basic Average Common Shares Outstanding			274.7				274.0					274.4				273.9
Diluted Average Common Shares			274.7				275.4					277.0				275.4

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

ITEM 1.		FINANCIAL STATEMENTS (continued)

Condensed Consolidated Balance Sheets (unaudited)

		June 30,				December 31,
(in millions)		2009				2008
ASSETS
Property, Plant and Equipment
Utility Plant		$	18,664.8			$	18,356.8
Accumulated depreciation and amortization			(8,232.9	)			(8,080.8	)
Net utility plant			10,431.9				10,276.0
Other property, at cost, less accumulated depreciation			111.2				112.1
Net Property, Plant and Equipment			10,543.1				10,388.1
Investments and Other Assets
Assets of discontinued operations and assets held for sale			180.3				178.3
Unconsolidated affiliates			146.4				86.8
Other investments			111.6				117.9
Total Investments and Other Assets			438.3				383.0
Current Assets
Cash and cash equivalents			248.9				20.6
Restricted cash			64.2				79.9
Accounts receivable (less reserve of $59.0 and $43.9, respectively)			544.7				1,027.0
Gas inventory			247.0				511.8
Underrecovered gas and fuel costs			1.8				180.2
Materials and supplies, at average cost			98.4				95.1
Electric production fuel, at average cost			81.2				63.7
Price risk management assets			24.5				118.3
Exchange gas receivable			163.7				371.6
Regulatory assets			286.3				314.9
Assets of discontinued operations and assets held for sale			495.7				416.8
Prepayments and other			180.3				217.7
Total Current Assets			2,436.7				3,417.6
Other Assets
Price risk management assets			70.7				95.7
Regulatory assets			1,597.3				1,640.4
Goodwill			3,677.3				3,677.3
Intangible assets			325.1				330.6
Postretirement and postemployment benefits assets			9.2				10.3
Deferred charges and other			125.6				123.5
Total Other Assets			5,805.2				5,877.8
Total Assets		$	19,223.3			$	20,066.5

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

ITEM 1.		FINANCIAL STATEMENTS (continued)

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

(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; 275,148,454
and 274,261,799 shares issued and outstanding, respectively		$	2.8			$	2.7
Additional paid-in capital			4,032.7				4,020.3
Retained earnings			855.1				901.1
Accumulated other comprehensive loss			(74.0	)			(172.0	)
Treasury stock			(24.2	)			(23.3	)
Total Common Stockholders’ Equity			4,792.4				4,728.8
Long-term debt, excluding amounts due within one year			6,564.4				5,943.9
Total Capitalization			11,356.8				10,672.7
Current Liabilities
Current portion of long-term debt			424.0				469.3
Short-term borrowings			-				1,163.5
Accounts payable			240.9				606.9
Dividends declared			63.3				-
Customer deposits			125.4				125.6
Taxes accrued			209.1				206.5
Interest accrued			125.4				120.1
Overrecovered gas and fuel costs			424.4				35.9
Price risk management liabilities			101.1				237.5
Exchange gas payable			319.4				555.5
Deferred revenue			20.2				4.3
Regulatory liabilities			35.1				40.4
Accrued liability for postretirement and postemployment benefits			7.1				6.4
Liabilities of discontinued operations and liabilities held for sale			261.2				158.1
Temporary LIFO liquidation credit			8.3				-
Legal and environmental reserves			328.3				375.1
Other accruals			249.2				486.1
Total Current Liabilities			2,942.4				4,591.2
Other Liabilities and Deferred Credits
Price risk management liabilities			5.1				17.9
Deferred income taxes			1,672.1				1,576.4
Deferred investment tax credits			42.9				46.1
Deferred credits			73.0				76.7
Deferred revenue			7.3				6.2
Accrued liability for postretirement and postemployment benefits			1,254.4				1,238.5
Liabilities of discontinued operations and liabilities held for sale			163.6				174.9
Regulatory liabilities and other removal costs			1,413.4				1,386.1
Asset retirement obligations			127.5				126.0
Other noncurrent liabilities			164.8				153.8
Total Other Liabilities and Deferred Credits			4,924.1				4,802.6
Commitments and Contingencies (Refer to Note 17)			-				-
Total Capitalization and Liabilities		$	19,223.3			$	20,066.5

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

ITEM 1.		FINANCIAL STATEMENTS (continued)

Condensed Statements of Consolidated Cash Flows (unaudited)

Six Months Ended June 30, (in millions)		2009				2008
Operating Activities
Net Income		$	143.6			$	(103.0	)
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Gain on Early Extinguishment of Debt			(2.5	)			-
Depreciation and Amortization			291.9				283.1
Net Changes in Price Risk Management Assets and Liabilities			1.7				19.4
Deferred Income Taxes and Investment Tax Credits			34.1				52.2
Deferred Revenue			15.9				(16.7	)
Stock Compensation Expense			4.9				4.5
Gain on Sale of Assets			(2.0	)			(4.1	)
Loss on Impairment of Assets			-				1.6
Income from Unconsolidated Affiliates			(3.8	)			(1.1	)
Loss on Disposition of Discontinued Operations - Net of Taxes			9.0				98.9
Loss (Income) from Discontinued Operations - Net of Taxes			(2.0	)			212.4
Amortization of Discount/Premium on Debt			6.2				3.7
AFUDC Equity			-				(4.1	)
Changes in Assets and Liabilities:
Accounts Receivable			413.2				207.1
Inventories			219.3				361.9
Accounts Payable			(327.1	)			(49.8	)
Customer Deposits			(0.2	)			(0.4	)
Taxes Accrued			81.9				10.8
Interest Accrued			5.3				0.6
(Under) Overrecovered Gas and Fuel Costs			566.8				(195.9	)
Exchange Gas Receivable/Payable			(22.4	)			15.0
Other Accruals			(213.3	)			(149.0	)
Prepayments and Other Current Assets			20.7				11.0
Regulatory Assets/Liabilities			52.2				(53.7	)
Postretirement and Postemployment Benefits			19.0				5.0
Deferred Credits			(7.7	)			1.7
Deferred Charges and Other NonCurrent Assets			0.7				(11.2	)
Other NonCurrent Liabilities			11.8				(30.6	)
Net Operating Activities from Continuing Operations			1,317.2				669.3
Net Operating Activities used for Discontinued Operations			(77.0	)			(30.9	)
Net Cash Flows from Operating Activities			1,240.2				638.4
Investing Activities
Capital Expenditures			(385.6	)			(448.7	)
Sugar Creek purchase			-				(329.7	)
Insurance Recoveries			54.6				25.9
Proceeds from Disposition of Assets			2.1				229.6
Restricted Cash			15.7				90.1
Other Investing Activities			(29.4	)			(2.1	)
Net Investing Activities used for Continuing Operations			(342.6	)			(434.9	)
Net Investing Activities from Discontinued Operations			22.7				47.3
Net Cash Flows used for Investing Activities			(319.9	)			(387.6	)
Financing Activities
Issuance of Long-Term Debt			963.5				706.0
Retirement of Long-Term Debt			(364.9	)			(12.0	)
Repurchase of Long-Term Debt			-				(254.0	)
Change in Short-Term Debt, Net			(1,163.5	)			(555.0	)
Issuance of Common Stock			0.4				0.8
Acquisition of Treasury Stock			(0.9	)			(0.2	)
Dividends Paid - Common Stock			(126.2	)			(126.1	)
Net Cash Flows used for Financing Activities			(691.6	)			(240.5	)
Increase in cash and cash equivalents from continuing operations			283.0				(6.1	)
Cash (contributions to) receipts from discontinued operations			(54.7	)			17.4
Cash and cash equivalents at beginning of period			20.6				34.6
Cash and Cash Equivalents at End of Period		$	248.9			$	45.9

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

ITEM 1.		FINANCIAL STATEMENTS (continued)

		Three Months								Six Months
		Ended June 30,								Ended June, 30
(in millions, net of taxes)		2009				2008				2009				2008
Net Income (Loss)		$	(4.8	)		$	(202.3	)		$	143.6			$	(103.0	)
Other comprehensive income
Net gain (loss) on available for sale securities (a)			1.5				(0.7	)			0.2				(2.0	)
Net unrealized gains on cash flow hedges (b)			111.1				10.0				96.6				27.3
Unrecognized pension benefit and OPEB costs (c)			0.6				0.6				1.2				(3.0	)
Total other comprehensive income			113.2				9.9				98.0				22.3
Total Comprehensive Income (Loss)		$	108.4			$	(192.4	)		$	241.6			$	(80.7	)

(a)		Net unrealized gain (loss) on available for sale securities, net of $1.1 million tax expense and $0.5 million tax benefit in the second quarter of 2009 and 2008, respectively, and $0.3 million tax expense and $1.3 million tax benefit for the first six months of 2009 and 2008, respectively.
(b)		Net unrealized gain on derivatives qualifying as cash flow hedges, net of $74.9 million and $6.8 million tax expense in second quarter of 2009 and 2008, respectively, and $64.7 million and $18.7 million tax expense for the first six months of 2009 and 2008, respectively.
(c)		Unrecognized pension benefit and OPEB costs recorded to accumulated other comprehensive income, net of $0.4 million and $0.8 tax expense in second quarter of 2009 and 2008, respectively, and $0.7 million tax expense and $1.8 million tax benefit for the first six months of 2009 and 2008, respectively.

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

ITEM 1.		FINANCIAL STATEMENTS (continued)

Notes to Condensed Consolidated Financial Statements (unaudited)

1.

Basis of Accounting Presentation

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.

NiSource’s management has performed an evaluation of subsequent events through August 4, 2009, which is the date the financial statements were issued.

2.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

SFAS No. 165 – Subsequent Events. In May 2009, the FASB issued SFAS No. 165. The standard does not require significant changes regarding recognition or disclosure of subsequent events, but does require disclosure of the date through which subsequent events have been evaluated for purposes of disclosure and accounting recognition. The standard was effective for financial statements issued after June 15, 2009. The adoption of this standard on April 1, 2009 did not have a material impact on the Condensed Consolidated Financial Statements (unaudited).

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 statements 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 was 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.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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

The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability.

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.

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 adopted this FSP on April 1, 2009.

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 was 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 was 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 entity’s involvement with variable interest entities. This FSP was 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). Refer to Note 11, “Transfers of Financial Assets,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding FSP FAS 140-4.

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. The adoption of this FSP on April 1, 2009 did not have a material impact on the Condensed Consolidated Financial Statements (unaudited).

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

ITEM 1.		FINANCIAL STATEMENTS (continued)

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

permitted. NiSource adopted this FSP on April 1, 2009. As this FSP provides only disclosure requirements, the application of this standard did not have a material impact on the Condensed Consolidated Financial Statements (unaudited). Refer to Note 10, “Fair Value Assets and Liabilities,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding FSP FAS 107-1.

Recently Issued Accounting Pronouncements

SFAS No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB Statement No. 162. In June 2009, the FASB issued SFAS No. 168 to address the new authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; rather, it will issue Accounting Standards Updates. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This Statement does not change GAAP and will not have a material impact on NiSource.

SFAS No. 167 – Amendments to FASB Interpretation No. 46(R). In June 2009, the FASB issued SFAS No. 167 to amend certain requirements of FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities, to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on the first fiscal year that begins after November 15, 2009 with early adoption prohibited. NiSource is currently reviewing the additional requirements to determine the impact on the Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements.

SFAS No. 166 – Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140. In June 2009, the FASB issued SFAS No. 166 to amend the derecognition guidance in Statement 140 to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on the first fiscal year that begins after November 15, 2009 with early adoption prohibited. NiSource is currently reviewing the accounting and additional disclosure requirements to determine the impact on the Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements. This Statement may require sales of accounts receivable, under the accounts receivable program discussed in Note 11, “Transfers of Financial Assets,” in the Notes to Condensed Consolidated Financial Statements (unaudited) to be recorded as debt on the Consolidated Balance Sheets effective January 1, 2010.

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.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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

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 for the three months ended June 30, 2009 is not presented since NiSource had a loss from continuing operations and net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during that period. The computation of diluted average common shares follows:

4.

Restructuring Activities

In response to the current economic conditions, in February 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 half of 2009, NiSource recorded a pre-tax restructuring charge, net of adjustments, of $19.8 million to “Operation and maintenance” expense on the Condensed Statement of Consolidated Income (Loss) (unaudited), which primarily includes costs related to severance and other employee related costs for approximately 360 employees. As of June 30, 2009, 246 employees had been severed from employment. 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				Adjustments				June 30, 2009
Gas Transmission and Storage initiative		$	-			$	20.4			$	(14.1	)		$	(0.6	)		$	5.7
Total		$	-			$	20.4			$	(14.1	)		$	(0.6	)		$	5.7

5.

Gas in Storage

Gas Distribution Operations prices 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 $8.3 million and $174.8 million during the first six months of 2009 and

ITEM 1.		FINANCIAL STATEMENTS (continued)

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 $31.4 million recorded for the first six months 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 June 30, 2009 were:

(in millions)
Assets of discontinued operations		Property, plant and				Accounts receivable,				Price Risk				Restricted
and held for sale:		equipment, net				net				assets				cash				Other assets				Total
Unregulated Natural Gas Marketing		$	0.7			$	39.1			$	397.0			$	191.2			$	22.5			$	650.5
Lake Erie Land			11.9				-				-				-				-				11.9
NiSource Corporate Services			6.2				-				-				-				-				6.2
NDC Douglas Properties			3.6				-				-				-				1.2				4.8
Columbia Transmission			2.6				-				-				-				-				2.6
Total		$	25.0			$	39.1			$	397.0			$	191.2			$	23.7			$	676.0
Liabilities of discontinued										Price risk				Tax				Other
operations and held for sale:		Debt				Accounts payable				liabilities				liabilities				liabilities				Total
Unregulated Natural Gas Marketing		$	-			$	32.1			$	376.2			$	8.4			$	2.6			$	419.3
NDC Douglas Properties			4.9				0.4				-				-				0.2				5.5
Total		$	4.9			$	32.5			$	376.2			$	8.4			$	2.8			$	424.8
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 operations		Property, plant and				Accounts receivable,				Price risk				Restricted
and held for sale:		equipment, net				net				assets				cash				Other assets				Total
Unregulated Natural Gas Marketing		$	0.6			$	123.7			$	137.1			$	206.7			$	80.4			$	548.5
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
Total		$	46.2			$	123.7			$	137.1			$	206.7			$	81.4			$	595.1
Liabilities of discontinued										Price risk				Tax				Other
operations and held for sale:		Debt				Accounts payable				liabilities				liabilities				liabilities				Total
Unregulated Natural Gas Marketing		$	-			$	94.6			$	219.6			$	-			$	13.5			$	327.7
NDC Douglas Properties			4.9				0.2				-				-				0.2				5.3
Total		$	4.9			$	94.8			$	219.6			$	-			$	13.7			$	333.0

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

NiSource is engaged in a process to sell its unregulated natural gas marketing business. Net assets for the unregulated natural gas marketing business of $231.2 million have been accounted for as assets and liabilities of

ITEM 1.		FINANCIAL STATEMENTS (continued)

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

discontinued operations and the results of operations and cash flows of the unregulated natural gas marketing business were classified as discontinued operations for all periods presented. As a result of the letter of intent signed during the second quarter of 2009, an impairment loss of $8.8 million, net of tax, was recognized during the second quarter of 2009.

Lake Erie Land, which is wholly-owned by NiSource, is in the process of selling real estate to a private real estate development group. NiSource accounts for the assets expected to be sold to the private developer during the next twelve months as assets held for sale. In the second quarter of 2009, the developer was unable to meet certain contractual obligations under the sale agreement, specifically the payment of an $11 million note receivable that was due on June 13, 2009. NiSource granted a limited extension for the payment of the note and began negotiations with another potential party to replace the original developer. In July 2009, NiSource signed a Letter of Intent with the new potential party. Based on the most probable scenarios as of June 30, 2009, the Lake Erie Land assets continue to meet criteria for assets 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.

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.

On June 18, 2009, Columbia Transmission received approval from the FERC to abandon by sale to an unaffiliated third party its Line R System in West Virginia, which includes certain natural gas pipeline and compression facilities. These assets held for sale have a net book value of $2.4 million. The sale transaction is expected to close sometime during the second half of 2009. Columbia Transmission continues to pursue FERC approval on the sale of certain other non-core assets.

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 six months ended June 30, 2008, an after tax loss of $31.9 million was included in Loss on Disposition of Discontinued Operations in the Condensed Statements of Consolidated Income (Loss) (unaudited).

On December 1, 2008, NiSource sold NiSource subsidiaries Northern Utilities and Granite State Gas 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 and six months ended June 30, 2008, an after tax loss of $3.4 million and $66.9 million, respectively, was included in Loss on Disposition of Discontinued Operations in the Condensed Statements of Consolidated Income (Loss) (unaudited).

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 has determined that it is no longer probable that the property will be sold within twelve months and therefore, reclassified the assets from assets held for sale to assets held and used during the quarter.

NiSource Retail Services, a wholly-owned subsidiary of NiSource, had been engaged in a process to sell certain assets. During April 2009 negotiations with a potential buyer were terminated. NiSource has determined that it is no longer probable that the property will be sold within twelve months and therefore, reclassified the assets from assets held for sale to assets held and used during the quarter.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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

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

		Three Months									Six Months
		Ended June 30,									Ended June 30,
(in millions)		2009				2008					2009				2008
Revenues from Discontinued Operations		$	126.5			$	306.2				$	423.8			$	738.6
Income (Loss) from discontinued operations			21.4				(335.7	)				4.1				(324.0	)
Income tax (benefit) expense			8.7				(116.5	)				2.1				(111.6	)
Income (Loss) from Discontinued Operations - net of taxes		$	12.7			$	(219.2	)			$	2.0			$	(212.4	)
Loss on Disposition of Discontinued Operations - net of taxes		$	(8.8	)		$	(2.8	)			$	(9.0	)		$	(98.9	)

The $8.8 million after-tax loss on the disposition of discontinued operations in the second quarter of 2009 related to NiSource’s decision to sell its unregulated natural gas marketing business. The loss on disposition of discontinued operations for the six months ended June 30, 2008 include the after tax loss on disposition related to the sales of Whiting Clean Energy, Northern Utilities and Granite State Gas of $31.9 million, $52.0 million and $14.9 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 six months of 2009 and 2008 are presented in the table below:

(in millions)		2009				2008
Balance as of January 1,		$	126.0			$	128.1
Accretion expense			0.3				0.4
Accretion recorded as a regulatory asset			3.6				2.8
Settlements			(2.4	)			(3.2	)
Balance as of June 30,		$	127.5			$	128.1

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 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 effective January 1, 2009. On July 8, 2009, the PUCO issued an Order approving Columbia of Ohio’s application, although the deferred balances shall not accrue

ITEM 1.		FINANCIAL STATEMENTS (continued)

carrying charges and Columbia of Ohio shall not seek recovery of pension and other postretirement benefits deferrals in a base rate proceeding for a period of five years. The amount deferred will be approximately $13.0 million for 2009, which will be reflected in the results for the third and fourth quarters of 2009.

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 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 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 June 8, 2009, Columbia of Virginia filed an Application with the VSCC for approval of a CARE Plan for a three-year period beginning January 1, 2010. The CARE Plan includes incentives for residential and small general service customers to actively pursue conservation and energy conservation measures, a surcharge designed to recover the costs of such measures on a real-time basis, and a performance-based incentive for the delivery of conservation and energy efficiency benefits. The CARE Plan also includes a rate decoupling mechanism designed to mitigate the impact of declining customer usage. The VSCC scheduled the matter for hearing on October 19, 2009.

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 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.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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.

Certain of the NiSource distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC’s approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction. On February 27, 2009, Columbia of Ohio filed an application to adjust its Infrastructure Replacement Program Rider to recover costs for risers and accelerated main replacements. On June 24, 2009, the PUCO approved a stipulation allowing Columbia of Ohio to implement the new rider rate July 1, 2009, resulting in an annual revenue increase of approximately $14 million.

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.

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 adding 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 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 added 100,000 Dth per day of transportation capacity and is fully subscribed on a 15-year contracted firm basis. Construction is complete and the project was placed in service on July 1, 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 was available beginning May 2009 and the remainder will be available no later than the fourth quarter of 2009. The expansion capacity is 58% contracted on a long-term, firm basis, with the FERC authorized market-based rates for these services.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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 requested an increase in base rates calculated to produce additional annual gross margin of $85.7 million. 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. Field hearings to record customer testimonies were held on March 3, 2009 and July 15, 2009. The OUCC and intervenors filed their cases-in-chief on May 8, 2009. Northern Indiana filed its rebuttal testimony on June 26, 2009. Northern Indiana made several minor changes to its revenue requirement, and, as a result the margin requirement in the rebuttal filing is $6 million less than the original request. Final hearings began on July 27, 2009. The case is expected to be resolved, and new electric rates effective during 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 certain electric customers of Northern Indiana will receive bill credits of approximately $55.1 million each year. The credits will continue at approximately the same annual level and per the same methodology, until the IURC 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 billing factor used to distribute the revenue credit to customers is based on historical electric usage, therefore, in times of higher usage and revenues the amount credited may exceed $55.1 million annually, but would be offset in a subsequent period. Credits amounting to $26.3 million and $25.1 million were recognized for electric customers for the first half 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 half of 2009, non-fuel cost credits of $3.7 million were deferred in accordance with the aforementioned orders. In addition, administrative, FERC and other fees of $3.5 million were deferred. In total, for the first half of 2009 and 2008, net MISO credits of $0.2 million and costs of $4.9 million, respectively, were deferred. In its base rate case, Northern Indiana proposes recovery over a four year amortization period of the cumulative amount of charges that were deferred as of December 31, 2008, and to recover, through a tracker, charges deferred between December 31, 2008 and the date of effective rates in this case. The aforementioned tracker is also proposed 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. On June 30, 2009, the IURC issued an Order in the subsequent phase of the ASM proceeding confirming that Northern Indiana is permitted to continue deferring non-fuel administrative costs.

Northern Indiana was 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 and on June 30, 2009, the IURC issued an Order authorizing Northern Indiana to recover fuel-related ASM charges in its FAC and to defer non-fuel charges. The market began on January 6, 2009. The impact of ASM will not have a material effect on cash flows or earnings.

ITEM 1.		FINANCIAL STATEMENTS (continued)

On November 7, 2008, the FERC issued an Order clarifying the RSG First Pass calculation and requiring the MISO to resettle the RSG market using the correct calculation and to pay refunds, or assess surcharges, to market participants, as appropriate, to correct a misinterpretation of an order issued by FERC in April 2006. Northern Indiana believes that it would have been entitled to a refund, with the amount subject to calculation by MISO. On June 12, 2009, however, FERC issued an order on rehearing in which it affirmed its prior order clarifying the method to calculate the RSG First Pass rate, but reversed its ruling requiring the MISO to pay refunds, and collect surcharges, on equitable grounds. Northern Indiana has asked FERC to reconsider its decision to deny refunds and that request remains pending.

MISO’s implementation of FERC’s April 2006 Order on the RSG First Pass calculation resulted in several million dollars of surcharges to Northern Indiana through market resettlements implemented during the summer of 2007. As a result, Northern Indiana and Ameren jointly filed a complaint with FERC on August, 10, 2007, contending that the RSG rates in effect were unjust and unreasonable. On November 10, 2008, the FERC issued an Order granting these complaints and ordering the MISO to calculate refunds and surcharges, as appropriate, back to the date of the complaint filed by Northern Indiana and Ameren, as authorized by Section 206 of the Federal Power Act. On May 6, 2009, however, the FERC issued an Order that upheld its decision granting the complaint, but largely reversed its directive requiring MISO to pay refunds, and collect surcharges, on equitable grounds. The FERC affirmed the refund and surcharge requirement only for those transactions that occurred after the date of the November 10, 2008 Order, instead of August 10, 2007, as it had previously required. Northern Indiana and Ameren have requested rehearing of the FERC’s May 6, 2009 Order, and that request remains pending.

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. Northern Indiana recorded an accrual for this matter in accordance with SFAS No. 5.

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%, less $4.5 million annually, the annual depreciation on the Mitchell plant, pursuant to the FAC-71 settlement. 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. On July 21, 2009, the Indiana Court of Appeals granted LaPorte County’s Motion to Dismiss the appeal filed with the court on July 16, 2009.

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 six months of 2009 and 2008, the amount of purchased power costs exceeding the benchmark amounted to $1.0 million and $6.5 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.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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. The Order was issued April 29, 2009. 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.

9.

Risk Management Activities

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. In the second quarter of 2009, NiSource engaged in a process to sell its unregulated natural gas marketing business. As a result of this decision, it became probable that certain forecasted transactions are no longer probable of occurring from a consolidated NiSource perspective, which triggered the mark-to-market of certain forward sales contracts that were previously exempt under the normal purchase and sale exception. In addition, the mark-to-market gains and losses deferred in accumulated other comprehensive income (loss) related to certain financial derivatives accounted for as a cash flow hedge were also recognized in income from discontinued operations during the quarter. 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 exception under SFAS No. 133, a contract’s fair value is not recognized in the Consolidated Financial Statements until the contract is settled.

ITEM 1.		FINANCIAL STATEMENTS (continued)

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, 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 exception 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 exception 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

ITEM 1.		FINANCIAL STATEMENTS (continued)

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.

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 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.

NiSource is also involved in commercial and industrial gas sales, whereby gas derivatives are utilized to hedge expected future gas purchases. These derivatives associated with commercial and industrial gas sales have generally been accounted for as cash flow hedges. NiSource also has corresponding forward physical sales contracts of natural gas with customers. These forward physical sales contracts are derivatives, which have generally qualified for, and for which NiSource has elected the normal purchase normal sales exception under SFAS No. 133, and which do not require mark-to-market accounting. In the second quarter of 2009, NiSource has engaged in a process to sell its unregulated natural gas marketing business. As a result of this decision, certain forecasted transactions are no longer probable to occur, which triggered the mark-to-market treatment of certain forward sales contracts that were previously exempt under the normal purchase and sale election. In addition, the mark-to-market gains and losses deferred in accumulated other comprehensive income (loss) related to certain financial derivatives accounted for as a cash flow hedge were also recognized in income from discontinued operations during the quarter. The physical sales contracts marked-to-market had a fair value pre-tax gain of approximately $149.9 million at June 30, 2009, while the financial cash flow hedge contracts recognized to income from discontinued operations in the same period had a fair value pre-tax loss of $126.4 million.

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

		June 30, 2009				December 31, 2008
Commodity Price Risk Program:
Gas price volatility program derivatives (MMDth)			28.8				31.2
PPS program derivatives (MMDth)			1.6				1.9
DependaBill program derivatives (MMDth)			0.5				0.3
Regulatory incentive program derivatives (MMDth)			6.6				2.9
Gas marketing program derivatives (MMDth) (a)			83.2				84.4
Gas marketing forward physical derivatives (MMDth) (b)			93.9				-
Electric energy program FTR derivatives (mw)			2,753				8,068

(a)

Basis contract volumes not included in the above table were 93.2 MMDth and 83.5 MMDth as of June 30, 2009 and December 31, 2008,

ITEM 1. FINANCIAL STATEMENTS (continued)

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

			respectively.
	(b)		Gas marketing forward physical derivatives at December 31, 2008 received the normal purchase normal sales exception under SFAS No. 133 and did not require mark-to-market accounting.

Interest Rate Risk Activities. NiSource recognizes that the prudent and selective use of derivatives may help it to lower its cost of debt capital and manage its interest rate exposure. NiSource Finance has entered into various “receive fixed” and “pay floating” interest rate swap agreements which modify the interest rate characteristics of its outstanding long-term debt from fixed to variable rate. These interest rate swaps also serve to hedge the fair market value of NiSource Finance’s outstanding debt portfolio. As of June 30, 2009, NiSource had $7.0 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. 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.

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 June 30 2009, $15.2 million is in accumulated other comprehensive loss related to forward starting interest rate swap settlement.

ITEM 1. FINANCIAL STATEMENTS (continued)

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

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

		June 30,				December 31,
Asset Derivatives(in millions)		2009				2008
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)		$	21.7			$	111.4
Price risk management assets (noncurrent)			-				(0.1	)
Assets of discontinued operations and assets held for sale (current)			-				32.1
Assets of discontinued operations and assets held for sale (noncurrent)			-				105.0
Interest rate risk activities
Price risk management assets (noncurrent)			70.7				95.8
Total derivatives designated as hedging instruments under SFAS No. 133		$	92.4			$	344.2
Derivatives not designated as hedging instruments under SFAS No. 133
Commodity price risk programs
Price risk management assets (current)		$	2.8			$	6.9
Price risk management assets (noncurrent)			-				-
Assets of discontinued operations and assets held for sale (current)			230.0				-
Assets of discontinued operations and assets held for sale (noncurrent)			167.0				-
Total derivatives not designated as hedging instruments under SFAS No. 133		$	399.8			$	6.9
Total Asset Derivatives		$	492.2			$	351.1
		June 30,				December 31,
Liability Derivatives(in millions)		2009				2008
Balance Sheet Location		Fair Value				Fair Value
Derivatives designated as hedging instruments under SFAS No. 133
Commodity price risk programs
Price risk management liabilities (current)		$	52.6			$	184.6
Price risk management liabilities (noncurrent)			0.6				0.8
Price risk management liabilities (current)							-
Liabilities of discontinued operations and liabilities held for sale (current)			-				49.0
Liabilities of discontinued operations and liabilities held for sale (noncurrent)							170.6
Interest rate risk activities
Price risk management liabilities (noncurrent)			-				-
Total derivatives designated as hedging instruments under SFAS No. 133		$	53.2			$	405.0
Derivatives not designated as hedging instruments under SFAS No. 133
Commodity price risk programs
Price risk management liabilities (current)		$	48.5			$	52.9
Price risk management liabilities (noncurrent)			4.5				17.1
Liabilities of discontinued operations and liabilities held for sale (current)			221.7				-
Liabilities of discontinued operations and liabilities held for sale (noncurrent)			154.5				-
Total derivatives not designated as hedging instruments under SFAS No. 133		$	429.2			$	70.0
Total Liability Derivatives		$	482.4			$	475.0

ITEM 1. FINANCIAL STATEMENTS (continued)

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

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

Derivatives in Cash Flow Hedging Relationships

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		June 30,				June 30,				into Income (Effective		June 30,				June 30,
Relationships		2009				2008				Portion)		2009				2008
Commodity price risk programs		$	110.7			$	9.6			Cost of Sales		$	19.0			$	16.3
Interest rate risk activities			0.4				0.4			Interest expense, net			(0.4	)			-
Total		$	111.1			$	10.0					$	18.6			$	16.3

Six 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		June 30,				June 30,				into Income (Effective		June 30,				June 30,
Relationships		2009				2008				Portion)		2009				2008
Commodity price risk programs		$	95.8			$	26.5			Cost of Sales		$	(24.8	)		$	25.4
Interest rate risk activities			0.8				0.8			Interest expense, net			(0.8	)			-
Total		$	96.6			$	27.3					$	(25.6	)		$	25.4