UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

or

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

For the transition period from ______ to ______

Commission file number 001-16189

(Exact name of registrant as specified in its charter)

Delaware		35-2108964
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
801 East 86th Avenue
Merrillville, Indiana		46410
(Address of principal executive offices)		(Zip Code)

(877) 647-5990

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)
Yes 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.

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: 277,442,244 shares outstanding at April 30, 2010.

NISOURCE INC.
FORM 10-Q QUARTERLY REPORT
FOR THE QUARTER ENDED March 31, 2010

				Page
		Defined Terms			3
PART I		FINANCIAL INFORMATION			5
		Item 1.     Financial Statements - unaudited			5
		Condensed Statements of Consolidated Income (unaudited)			5
		Condensed Consolidated Balance Sheets (unaudited)			6
		Condensed Statements of Consolidated Cash Flows (unaudited)			8
		Condensed Statements of Consolidated Comprehensive Income (unaudited)			9
		Notes to Condensed Consolidated Financial Statements (unaudited)			10
		Item 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations			46
		Item 3.     Quantitative and Qualitative Disclosures About Market Risk			76
		Item 4.     Controls and Procedures			76
PART II		OTHER INFORMATION			77
		Item 1.     Legal Proceedings			77
		Item1A. Risk Factors			78
		Item 2.     Unregistered Sales of Equity Securities and Use of Proceeds			78
		Item 3.     Defaults Upon Senior Securities			78
		Item 4.     (Removed and Reserved)			78
		Item 5.     Other Information			78
		Item 6.     Exhibits			79
		Signature			80
EX-10.1
EX-10.2
EX-10.3
EX-10.4
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.
CGORC		Columbia Gas of Ohio Receivables Corporation
CNR		Columbia Natural Resources, Inc.
Columbia		Columbia Energy Group
Columbia Gulf		Columbia Gulf Transmission Company
Columbia of Kentucky		Columbia Gas of Kentucky, Inc.
Columbia of Maryland		Columbia Gas of Maryland, Inc.
Columbia of 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
CPRC		Columbia of Pennsylvania Receivables Corporation
Crossroads Pipeline		Crossroads Pipeline Company
Granite State Gas		Granite State Gas Transmission, Inc.
Hardy Storage		Hardy Storage Company, L.L.C.
Kokomo Gas		Kokomo Gas and Fuel Company
Millennium		Millennium Pipeline Company, L.L.C.
NARC		NIPSCO Accounts Receivable Corporation
NDC Douglas Properties		NDC Douglas Properties, Inc.
NiSource		NiSource Inc.
NiSource Corporate Services		NiSource Corporate Services Company
NiSource Development Company		NiSource Development Company, Inc.
NiSource Finance		NiSource Finance Corp.
Northern Indiana		Northern Indiana Public Service Company
Northern Indiana Fuel and Light		Northern Indiana Fuel and Light Company
Northern Utilities		Northern Utilities, Inc.
PEI		PEI Holdings, Inc.
Whiting Clean Energy		Whiting Clean Energy, Inc.

Abbreviations
2010 Health Care Act		The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 signed into law by the President on March 23, 2010 and March 30, 2010, respectively
ACES		American Clean Energy and Security Act of 2009
AFUDC		Allowance for funds used during construction
Ameren		Ameren Services Company
AMRP		Accelerated Main Replacement Program
AOC		Administrative Order by Consent
AOCI		Accumulated other comprehensive income
ARRs		Auction Revenue Rights
ASC		Accounting Standards Codification
BBA		British Banker Association
Bcf		Billion cubic feet
Board		Board of Directors
BPAE		BP Alternative Energy North America Inc
BTMU		The Bank of Tokyo-Mitsubishi UFJ, LTD.
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CARE		Conservation and Ratemaking Efficiency

DEFINED TERMS (continued)

CCGT		Combined Cycle Gas Turbine
CERCLA		Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
Chesapeake		Chesapeake Appalachia, L.L.C.
Day 2		Began April 1, 2005 and refers to the operational control of the energy markets by MISO, including the dispatching of wholesale electricity and generation, managing transmission constraints, and managing the day-ahead, real-time and financial transmission rights markets
DPU		Department of Public Utilities
DSM		Demand Side Management
Dth		Dekatherm
ECR		Environmental Cost Recovery
ECRM		Environmental Cost Recovery Mechanism
ECT		Environmental cost tracker
EERM		Environmental Expense Recovery Mechanism
EPA		United States Environmental Protection Agency
EPS		Earnings per share
FAC		Fuel adjustment clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FTRs		Financial Transmission Rights
GAAP		U.S. Generally Accepted Accounting Principles
GCR		Gas cost recovery
GHG		greenhouse gases
gwh		Gigawatt hours
IDEM		Indiana Department of Environmental Management
IFRS		International Financial Reporting Standards
IRP		Infrastructure Replacement Program
IURC		Indiana Utility Regulatory Commission
LDCs		Local distribution companies
LIBOR		London InterBank Offered Rate
LIFO		Last in first out
Mcf		Million cubic feet
MISO		Midwest Independent Transmission System Operator
Mitchell		Dean H. Mitchell Coal Fired Generating Station
MMDth		Million dekatherms
mw		Megawatts
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NO2		Nitrogen dioxide
NOx		Nitrogen oxide
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income (Loss)
OUCC		Indiana Office of Utility Consumer Counselor
PADEP		Pennsylvania Department of Environmental Protection
Piedmont		Piedmont Natural Gas Company, Inc.
PIPP		Percentage of Income Plan
PJM		PJM Interconnection is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.
PM		particulate matter
PPUC		Pennsylvania Public Utility Commission
PSC		Public Service Commission
PUC		Public Utility Commission
PUCO		Public Utilities Commission of Ohio
RBS		Royal Bank of Scotland PLC
RCRA		Resource Conservation and Recovery Act
RSG		Revenue Sufficiency Guarantee
SEC		Securities and Exchange Commission
SIP		State Implementation Plan
SO2		Sulfur dioxide
VaR		Value-at-risk and instrument sensitivity to market factors
VIE		Variable Interest Entities
VSCC		Virginia State Corporation Commission

PART I

ITEM 1.  FINANCIAL STATEMENTS

NiSource Inc.

Three Months Ended March 31, (in millions, except per share amounts)		2010				2009
Net Revenues
Gas Distribution		$	1,341.1			$	1,716.9
Gas Transportation and Storage			370.4				396.2
Electric			317.9				296.8
Other			328.9				311.8
Gross Revenues			2,358.3				2,721.7
Cost of Sales (excluding depreciation and amortization)			1,286.3				1,655.5
Total Net Revenues			1,072.0				1,066.2
Operating Expenses
Operation and maintenance			439.4				479.1
Depreciation and amortization			149.8				143.7
Impairment and loss/(gain) on sale of assets, net			0.1				(2.0	)
Other taxes			86.9				103.4
Total Operating Expenses			676.2				724.2
Equity Earnings in Unconsolidated Affiliates			7.4				6.4
Operating Income			403.2				348.4
Other Income (Deductions)
Interest expense, net			(98.7	)			(90.4	)
Other, net			2.6				(4.2	)
Gain on early extinguishment of long-term debt			-				3.2
Total Other Income (Deductions)			(96.1	)			(91.4	)
Income from Continuing Operations before Income Taxes			307.1				257.0
Income Taxes			109.8				97.6
Income from Continuing Operations			197.3				159.4
Loss from Discontinued Operations - net of taxes			(0.1	)			(10.8	)
Gain (Loss) on Disposition of Discontinued Operations - net of taxes			0.1				(0.2	)
Net Income		$	197.3			$	148.4
Basic Earnings (Loss) Per Share
Continuing operations		$	0.71			$	0.58
Discontinued operations			-				(0.04	)
Basic Earnings Per Share		$	0.71			$	0.54
Diluted Earnings (Loss) Per Share
Continuing operations		$	0.71			$	0.58
Discontinued operations			-				(0.04	)
Diluted Earnings Per Share		$	0.71			$	0.54
Dividends Declared Per Common Share		$	0.46			$	0.46
Basic Average Common Shares Outstanding			276.9				274.2
Diluted Average Common Shares			277.5				276.7

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

NiSource Inc.

		March 31,				December 31,
(in millions)		2010				2009
ASSETS
Property, Plant and Equipment
Utility Plant		$	19,049.3			$	18,946.1
Accumulated depreciation and amortization			(8,443.5	)			(8,353.7	)
Net utility plant			10,605.8				10,592.4
Other property, at cost, less accumulated depreciation			91.4				91.5
Net Property, Plant and Equipment			10,697.2				10,683.9
Investments and Other Assets
Assets of discontinued operations and assets held for sale			12.9				18.7
Unconsolidated affiliates			166.8				165.8
Other investments			129.1				129.2
Total Investments and Other Assets			308.8				313.7
Current Assets
Cash and cash equivalents			110.6				16.4
Restricted cash			220.8				174.7
Accounts receivable (less reserve of $68.6 and $39.6, respectively)			949.9				808.6
Income tax receivable			2.9				24.9
Gas inventory			79.0				384.8
Underrecovered gas and fuel costs			114.4				40.2
Materials and supplies, at average cost			98.5				102.3
Electric production fuel, at average cost			52.4				59.9
Price risk management assets			190.4				173.3
Exchange gas receivable			71.3				72.5
Regulatory assets			169.6				238.3
Assets of discontinued operations and assets held for sale			0.7				2.2
Prepayments and other			136.7				125.5
Total Current Assets			2,197.2				2,223.6
Other Assets
Price risk management assets			271.3				237.6
Regulatory assets			1,720.0				1,644.1
Goodwill			3,677.3				3,677.3
Intangible assets			316.8				319.6
Postretirement and postemployment benefits assets			22.8				19.8
Deferred charges and other			140.2				152.1
Total Other Assets			6,148.4				6,050.5
Total Assets		$	19,351.6			$	19,271.7

  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)

		March 31,				December 31,
(in millions, except share amounts)		2010				2009
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 277,290,886 and 276,638,021 shares issued and outstanding, respectively		$	2.8			$	2.8
Additional paid-in capital			4,068.5				4,057.6
Retained earnings			935.3				865.5
Accumulated other comprehensive loss			(50.4	)			(45.9	)
Treasury stock			(27.4	)			(25.9	)
Total Common Stockholders’ Equity			4,928.8				4,854.1
Long-term debt, excluding amounts due within one year			5,963.9				5,965.1
Total Capitalization			10,892.7				10,819.2
Current Liabilities
Current portion of long-term debt			723.1				719.3
Short-term borrowings			370.7				103.0
Accounts payable			407.1				502.1
Dividends payable			64.0				0.2
Customer deposits and credits			176.5				301.2
Taxes accrued			296.8				212.9
Interest accrued			84.1				125.4
Overrecovered gas and fuel costs			43.5				220.4
Price risk management liabilities			211.1				190.1
Exchange gas payable			151.4				222.2
Deferred revenue			11.5				27.3
Regulatory liabilities			51.7				43.8
Accrued liability for postretirement and postemployment benefits			7.6				23.6
Liabilities of discontinued operations and liabilities held for sale			0.9				1.7
Temporary LIFO liquidation credit			42.2				-
Legal and environmental reserves			97.5				146.1
Other accruals			257.5				310.3
Total Current Liabilities			2,997.2				3,149.6
Other Liabilities and Deferred Credits
Price risk management liabilities			200.6				170.2
Deferred income taxes			2,053.3				2,018.2
Deferred investment tax credits			38.1				39.6
Deferred credits			71.9				72.4
Deferred revenue			9.0				8.5
Accrued liability for postretirement and postemployment benefits			1,190.8				1,134.2
Liabilities of discontinued operations and liabilities held for sale			3.9				10.2
Regulatory liabilities and other removal costs			1,571.4				1,558.8
Asset retirement obligations			139.7				138.2
Other noncurrent liabilities			183.0				152.6
Total Other Liabilities and Deferred Credits			5,461.7				5,302.9
Total Capitalization and Liabilities		$	19,351.6			$	19,271.7

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

NiSource Inc.

Three Months Ended March 31, (in millions)		2010				2009
Operating Activities
Net Income		$	197.3			$	148.4
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Gain on Early Extinguishment of Debt			-				(3.2	)
Depreciation and Amortization			149.8				143.7
Net Changes in Price Risk Management Assets and Liabilities			(7.4	)			(1.7	)
Deferred Income Taxes and Investment Tax Credits			27.2				23.1
Deferred Revenue			(15.8	)			(3.7	)
Stock Compensation Expense			2.2				1.6
Gain on Sale of Assets			(0.1	)			(2.0	)
Income from Unconsolidated Affiliates			(7.4	)			(6.4	)
(Gain) Loss on Disposition of Discontinued Operations - Net of Taxes			(0.1	)			0.2
Loss from Discontinued Operations - Net of Taxes			0.1				10.8
Amortization of Discount/Premium on Debt			2.7				2.1
AFUDC Equity			(1.4	)			0.9
Changes in Assets and Liabilities:
Accounts Receivable			(138.4	)			172.0
Income Tax Receivable			22.1				-
Inventories			332.7				487.7
Accounts Payable			(103.0	)			(161.0	)
Customer Deposits and Credits			(124.7	)			(114.6	)
Taxes Accrued			96.4				81.9
Interest Accrued			(38.9	)			(23.4	)
(Under) Overrecovered Gas and Fuel Costs			(251.1	)			446.3
Exchange Gas Receivable/Payable			(66.7	)			(80.1	)
Other Accruals			(17.2	)			(69.3	)
Prepayments and Other Current Assets			5.4				8.8
Regulatory Assets/Liabilities			47.8				32.3
Postretirement and Postemployment Benefits			1.3				11.3
Deferred Credits			(1.1	)			(3.4	)
Deferred Charges and Other NonCurrent Assets			(2.6	)			11.8
Other Noncurrent Liabilities			5.3				5.7
Net Operating Activities from Continuing Operations			114.4				1,119.8
Net Operating Activities used for Discontinued Operations			(31.1	)			(61.9	)
Net Cash Flows from Operating Activities			83.3				1,057.9
Investing Activities
Capital Expenditures			(138.8	)			(206.9	)
Insurance Recoveries			0.5				52.0
Proceeds from Disposition of Assets			0.2				2.1
Restricted Cash			(46.1	)			(30.2	)
Contributions to Equity Investments			-				(10.7	)
Other Investing Activities			(10.6	)			(10.2	)
Net Investing Activities used for Continuing Operations			(194.8	)			(203.9	)
Net Investing Activities from Discontinued Operations			0.4				7.5
Net Cash Flows used for Investing Activities			(194.4	)			(196.4	)
Financing Activities
Issuance of Long-Term Debt			-				581.7
Retirement of Long-Term Debt			(0.9	)			(101.4	)
Change in Short-Term Debt, Net			267.7				(1,163.5	)
Issuance of Common Stock			3.6				0.2
Acquisition of Treasury Stock			(1.4	)			(0.8	)
Dividends Paid - Common Stock			(63.7	)			(63.1	)
Net Cash Flows used for Financing Activities			205.3				(746.9	)
Change in cash and cash equivalents from continuing operations			124.9				169.0
Cash contributions to discontinued operations			(30.7	)			(54.4	)
Cash and cash equivalents at beginning of period			16.4				20.6
Cash and Cash Equivalents at End of Period		$	110.6			$	135.2

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

NiSource Inc.

Three Months Ended March 31, (in millions, net of taxes)		2010				2009
Net Income		$	197.3			$	148.4
Other comprehensive income (loss)
Net gain (loss) on available for sale securities (a)			0.5				(1.3	)
Net unrealized losses on cash flow hedges (b)			(2.9	)			(14.5	)
Unrecognized pension benefit and OPEB costs (c)			0.5				0.6
Total other comprehensive loss			(1.9	)			(15.2	)
Total Comprehensive Income		$	195.4			$	133.2

(a)		Net unrealized gain (loss) on available-for-sale securities, net of $0.3 million tax expense and $0.8 million tax benefit in the first quarter of 2010 and 2009, respectively.
(b)		Net unrealized gains (losses) on derivatives qualifying as cash flow hedges, net of $1.8 million and $10.2 million tax benefit in the first quarter of 2010 and 2009, respectively.
(c)		Unrecognized pension benefit and OPEB costs, net of $0.3 million tax expense in both the first quarter of 2010 and 2009.

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

NiSource Inc.

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, 2009. 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.

2.          Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Transfer of Financial Assets. In June 2009, the FASB issued authoritative guidance to amend derecognition criteria guidance in ASC 860 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. NiSource adopted the guidance on January 1, 2010. This guidance requires transfers of accounts receivable that previously qualified for sales accounting to be accounted for as secured borrowings resulting in the recognition of short-term debt on the Condensed Consolidated Balance Sheets (unaudited). Refer to Note 11, “Transfers of Financial Assets,” for additional information.

Consolidation of Variable Interest Entities. In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders were required to determine whether they retained a controlling financial interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. In contrast, the new guidance requires an enterprise with a variable interest in a VIE to qualitatively assess whether it has a controlling financial interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation, rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. NiSource adopted the guidance on January 1, 2010. Refer to Note 15, “Variable Interests and Variable Interest Entities,” for additional information.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

Fair Value Measurements and Disclosures. In January 2010, the FASB issued authoritative guidance that amends the disclosures about transfers into and out of Level 1 and 2 and requires separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. This guidance also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. This guidance is effective for the first reporting period, including interim periods, beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. Early adoption is permitted. NiSource adopted the additional guidance on January 1, 2010 with the exception of the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis. NiSource is currently reviewing the additional Level 3 disclosure requirements to determine the impact on the Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). Refer to Note 10, “Fair Value Disclosures,” for additional information.

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 includes the incremental effects of the various long-term incentive compensation plans. The calculation of diluted earnings per share for March 31, 2010 and 2009 excludes out-of-the-money stock options that had an anti-dilutive effect. The numerator in calculating both basic and diluted EPS for each period is reported net income. The computation of diluted average common shares follows:

Three Months Ended March 31, (in thousands)		2010				2009
Denominator
Basic average common shares outstanding			276,947				274,196
Dilutive potential common shares
Shares contingently issuable under employee stock plans			281				2,413
Shares restricted under employee stock plans			287				108
Diluted Average Common Shares			277,515				276,717

4.          Restructuring Activities

During the first quarter of 2009, NiSource began an organizational restructuring initiative in response to the decline in overall economic conditions.

In February 2009, NiSource announced the restructuring of the Gas Transmission and Storage Operations segment. NiSource has eliminated positions across the 16 state operating territory of Gas Transmission and Storage. The reductions have occurred through voluntary programs and involuntary separations. In addition to employee reductions, the Gas Transmission and Storage Operations segment took steps to achieve additional cost savings by efficiently managing its various business locations, reducing its fleet operations, creating alliances with third party service providers, and implementing other changes in line with its strategic plan for growth and maximizing value of existing assets. During the first quarter of 2009, NiSource recorded a pre-tax restructuring charge of $19.8 million and no additional charge for the first quarter of 2010. As of March 31, 2010, 316 employees had been terminated from employment. This program was substantially completed in 2009. The remaining employees impacted by the restructuring will be severed and will receive benefits in 2010.

In September 2009, NiSource announced the restructuring of Northern Indiana, which aims to redefine business and operations strategies and achieve cost reductions, and impacts both Electric Operations and Gas Distribution Operations. During 2009, NiSource recorded a pre-tax restructuring charge related to this initiative, net of adjustments, of $5.4 million, which primarily includes costs related to severance and other employee related costs for approximately 43 employees and outside services costs. During the first quarter of 2010, NiSource recorded a pre-tax restructuring charge related to this initiative of $1.0 million to “Operation and maintenance” expense on the Condensed Statements of Consolidated Income (unaudited), which primarily includes costs related to outside service costs. As of March 31, 2010, 36 employees had been terminated from employment. This program is expected to be completed in 2010.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

Changes in the restructuring reserve, included in “Other accruals” on the Condensed Consolidated Balance Sheets (unaudited), were as follows:

		Balance at																Balance at
(in millions)		December 31, 2009				Additions				Benefits Paid				Adjustments				March 31, 2010
2009 Initiative:
Gas Transmission and Storage		$	1.5			$	-			$	(0.9	)		$	-			$	0.6
Northern Indiana			1.1				1.0				(1.1	)			-				1.0
Total		$	2.6			$	1.0			$	(2.0	)		$	-			$	1.6

5.          Gas in Storage

Gas Distribution Operations price natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, NiSource expects interim variances in LIFO layers to be replenished by year-end. Changes between the temporary LIFO liquidation credits in the amounts of $42.2 million and $111.3 million during the first quarter of 2010 and 2009, respectively, are considered a non-cash activity for the Condensed Statements of Consolidated Cash Flows (unaudited). In addition to the temporary LIFO liquidation credit described above, NiSource also has a temporary LIFO liquidation debit of $21.3 million recorded for the first quarter of 2010 for certain gas distribution companies recorded within, “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

6.          Discontinued Operations and Assets and Liabilities Held for Sale

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

(in millions)
						Property, plant and
Assets of discontinued operations and held for sale:						equipment, net				Other assets				Total
NiSource Corporate Services						$	6.2			$	-			$	6.2
NDC Douglas Properties							4.1				0.7				4.8
Columbia Transmission							2.6				-				2.6
Total						$	12.9			$	0.7			$	13.6
Liabilities of discontinued operations and held for sale:		Debt				Accounts payable				Other liabilities				Total
NDC Douglas Properties		$	4.4			$	0.2			$	0.2			$	4.8
Total		$	4.4			$	0.2			$	0.2			$	4.8

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

The assets and liabilities of discontinued operations and held for sale on the Consolidated Balance Sheet at December 31, 2009 were:

(in millions)
						Property, plant and
Assets of discontinued operations and held for sale:						equipment, net				Other assets				Total
NiSource Corporate Services						$	6.2			$	-			$	6.2
NDC Douglas Properties							9.9				2.2				12.1
Columbia Transmission							2.6				-				2.6
Total						$	18.7			$	2.2			$	20.9
Liabilities of discontinued operations and held for sale:		Debt				Accounts payable				Other liabilities				Total
NDC Douglas Properties		$	11.0			$	0.6			$	0.3			$	11.9
Total		$	11.0			$	0.6			$	0.3			$	11.9

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

NiSource Corporate Services is continuing to work with a potential buyer to sell its Marble Cliff facility. A third party appraisal was performed in December 2009 with an estimated market value of the property slightly higher than 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. Three of these properties were sold during the first quarter of 2010 and two of these properties remain classified as assets and liabilities held for sale. Results of operations and cash flows for these properties are classified as discontinued operations. Based on the expected proceeds from the sale of the five properties being less than the net book value, an impairment charge of $2.7 million, net of tax, was included in Loss on Disposition of Discontinued Operations in the Statements of Consolidated Income for the year ended December 31, 2009. Upon sale of three of the properties in the first quarter of 2010, a gain on sale of $0.1 million, net of taxes, was recorded in Discontinued Operations. The remaining two properties are expected to be sold in the second half of 2010.

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 in 2010.

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

Three Months Ended March 31, (in millions)		2010				2009
Revenues from Discontinued Operations		$	1.1			$	0.9
Loss from discontinued operations			(0.1	)			(17.6	)
Income tax benefit			-				(6.8	)
Loss from Discontinued Operations - net of taxes		$	(0.1	)		$	(10.8	)
Gain (Loss) on Disposition of Discontinued Operations - net of taxes		$	0.1			$	(0.2	)

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

7.          Asset Retirement Obligations

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 three months of 2010 and 2009 are presented in the table below:

(in millions)		2010				2009
Balance as of January 1,		$	138.2			$	126.0
Accretion expense			0.2				0.2
Accretion recorded as a regulatory asset			1.8				1.7
Settlements			(0.5	)			(2.2	)
Balance as of March 31,		$	139.7			$	125.7

8.          Regulatory Matters

Gas Distribution Operations Regulatory Matters

Significant Rate Developments. On May 3, 2010, Northern Indiana filed a natural gas rate case with the IURC, the first since 1987, proposing enhanced low income assistance and extending energy-efficiency programs for customers, as well as a change in rate design. Among other things, the filing also proposes a mechanism for the deferral of certain pension and other postretirement costs and for adjustments to depreciation rates and expense. New rates are targeted to be effective by early 2011 or sooner.

In March 2009, Indiana Governor Daniels signed Senate Bill 423 into law giving the Indiana Finance Authority the ability to contract, on behalf of gas customers in the state of Indiana, with developers capable of building facilities that manufacture Substitute Natural Gas from coal. The Indiana Finance Authority received one bid, from Indiana Gasification, by the April 9, 2009 deadline to initiate a Substitute Natural Gas plant in Southern Indiana under a 30 year contract. Current law requires that all Indiana gas utilities, including Northern Indiana, deliver a portion of Substitute Natural Gas from this facility, once it is built. The IURC must approve the final contract between the Indiana Finance Authority and Indiana Gasification.

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

On December 9, 2009, Northern Indiana filed a Petition with the IURC to extend its alternative regulatory programs which was scheduled to expire on May 1, 2010. On February 12, 2010, Northern Indiana, the OUCC and gas marketers supplying gas to residential and small commercial customers filed a Joint Stipulation and Agreement proposing an extension to the programs through March 31, 2012, which was approved by the IURC on March 31, 2010.

On January 15, 2009, Columbia of Ohio filed an application with the PUCO requesting authority to increase Columbia of Ohio’s PIPP rider rate in order to collect $82.2 million in PIPP arrearages over a period of three years, in addition to the projected level of arrearages expected to occur during each of the succeeding twelve-month periods. On March 3, 2009, Columbia of Ohio’s proposal was approved and became effective.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

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

On February 27, 2009, Columbia of Ohio filed an application to adjust rates associated with Rider IRP. Rider IRP recovers costs associated with the replacement of natural gas risers that are prone to failure; maintenance, repair and replacement of customers service lines; an Accelerated Mains Replacement Program; and installation of Automatic Meter Reading Devices. On June 2, 2009, Columbia of Ohio filed a Joint Stipulation and Recommendation that settled all issues. On June 24, 2009, the PUCO issued an Order approving the Stipulation. Rates associated with Rider IRP were increased by $13.8 million annually beginning in July 2009.

On February 26, 2010, Columbia of Ohio filed an application to adjust rates associated with Riders IRP and DSM. Rider DSM tracks and recovers costs associated with Columbia of Ohio’s energy efficiency and conservation programs. On April 14, 2010, Columbia of Ohio filed a Joint Stipulation and Recommendation that settled all issues. On April 28, 2010, the PUCO issued an Order approving the Stipulation. Rates associated with Riders IRP and DSM were increased by approximately $17.8 million annually, beginning April 29, 2010.

On January 28, 2010, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $32 million annually. Columbia of Pennsylvania anticipates a final order will be received and new rates will go into effect in the fourth quarter of 2010.

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 and new rates were effective March 31, 2009.

On January 28, 2010, Columbia of Maryland filed a base rate case with the Maryland PSC, seeking a revenue increase of $2.2 million annually in order for Columbia of Maryland to earn the rate of return authorized by the PSC in its 2008 rate case. Columbia of Maryland anticipates a final order will be received and new rates will go into effect in the second quarter of 2010.

On April 16, 2009, Bay State filed a base rate case with the Massachusetts DPU, requesting an annual increase of $34.2 million. In its initial filing, Bay State sought revenue decoupling, as well as a mechanism for the recovery of costs associated with the replacement of its infrastructure. On October 30, 2009, the Massachusetts DPU issued a decision granting the company a $19.1 million base rate increase and approving the company’s proposed revenue decoupling mechanism and infrastructure replacement program. New rates went into effect November 1, 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 sought enhancements to rate design, as well as an expedited mechanism for the recovery of costs associated with the replacement of its infrastructure. A settlement agreement with all parties was presented in a hearing before the Kentucky PSC on September 18, 2009. The settlement agreement provided for a base rate increase of approximately $6 million, the authorization of an increase to the monthly customer charge, the implementation of an Accelerated Main Replacement Program rider and the introduction of a residential energy efficiency program. On October 26, 2009, the Kentucky PSC approved the settlement agreement as filed, with new rates taking effect on October 27, 2009.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

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 included incentives for residential and small general service customers to actively pursue conservation and energy efficiency 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 included a rate decoupling mechanism designed to mitigate the impact of declining customer usage. On October 28, 2009, Columbia of Virginia and other parties to the proceeding presented a unanimous settlement to the Hearing Examiner, which provided for approval of the CARE Plan Application with modifications. The settlement was approved by the VSCC on December 4, 2009, with mechanisms becoming effective January 1, 2010.

On May 3, 2010, Columbia of Virginia filed a rate case for $13.0 million with the VSCC seeking to increase customer rates to reflect current costs upon the expiration of its Performance Based Regulation Plan that is scheduled to expire on December 31, 2010.

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

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

Comparability of Gas Distribution Operations line item operating results is impacted by 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 Rider IRP 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 on July 1, 2009, resulting in an annual revenue increase of $13.8 million. On February 26, 2010, Columbia of Ohio filed an application to adjust rates associated with Riders IRP and DSM. Rider DSM tracks and recovers costs associated with Columbia of Ohio’s energy efficiency and conservation programs. On April 14, 2010, Columbia of Ohio filed a Joint Stipulation and Recommendation that settled all issues. On April 28, 2010, the PUCO issued an Order approving the Stipulation. Rates associated with Riders IRP and DSM were increased by approximately $17.8 million annually, beginning April 29, 2010. On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s Accelerated Main Replacement Program. In the same Order the Kentucky PSC also approved a mechanism for the recovery of Columbia of Kentucky’s uncollectible expenses associated with the cost of gas. Columbia of Kentucky filed an application to increase its AMRP Rider on March 31, 2010. On October 30, 2009, the Massachusetts DPU approved a mechanism for the recovery of costs associated with the replacement of Bay State’s infrastructure. Bay State filed an application to increase its Targeted Infrastructure Replacement Factor Rider on April 30, 2010.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

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 will not accrue carrying charges and Columbia of Ohio may not seek recovery of pension and other postretirement benefits deferrals in a base rate proceeding for a period of five years from the date of the Order. Approximately $1.8 million has been deferred in 2010 and $13.0 million was deferred for the year 2009.

Gas Transmission and Storage Operations Regulatory Matters

Majorsville, PA Project. The Gas Transmission and Storage Operations segment is in the process of executing three separate projects totaling approximately $80 million in the Majorsville, PA vicinity to aggregate Marcellus Shale gas production for downstream transmission. Precedent Agreements were executed by anchor shippers in the fourth quarter of 2009. On January 20, 2010, Columbia Transmission filed with the FERC an application to transfer certain pipeline facilities to a newly formed affiliate, NiSource Midstream, LLC, that, once approved, will be part of the facilities providing non-FERC jurisdiction gathering services to producers in the Majorsville, PA vicinity. The Majorsville, PA project is expected to begin service during the third quarter 2010.

Electric Operations Regulatory Matters

Significant Rate Developments. On June 27, 2008, Northern Indiana filed a petition for new electric base rates and charges. Northern Indiana filed its last electric base rate increase in 1986. The filing requested an increase in base rates calculated to produce additional gross margin of $85.7 million. Several stakeholder groups have intervened in the case, representing customer groups and various counties and towns within Northern Indiana’s electric service territory. Evidentiary hearings concluded on August 6, 2009, and the briefing schedule concluded in January 2010. An Order is expected during the second quarter of 2010.

Northern Indiana received a favorable regulatory order on February 18, 2009 related to its actions to increase its electric generating capacity and advance its electric rate case. Acting on a settlement reached among Northern Indiana and its regulatory stakeholders, the IURC ruled that Northern Indiana’s Sugar Creek electric generating plant was in service for ratemaking purposes as of December 1, 2008. The IURC also approved the deferral of depreciation expenses and carrying costs associated with the $330 million Sugar Creek investment. Northern Indiana purchased Sugar Creek on May 30, 2008 and effective December 1, 2008, Sugar Creek was accepted as an internal designated network resource within the MISO.

Northern Indiana anticipates filing another electric base rate case during 2010. Among other things, the filing is expected to include the effect of increased pension expense, as well as usage levels based on more recent operating experience.

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 new rates take effect based on an IURC order in the 2008 electric rate case. Credits amounting to $14.2 million and $13.2 million were recognized for electric customers for the first quarters of 2010 and 2009, respectively.

On December 9, 2009, the IURC issued an order in its generic DSM investigation proceeding establishing an overall annual energy savings goal of 2% to be achieved by Indiana jurisdictional electric utilities in 10 years, with interim savings goals established in years one through nine. Northern Indiana and other jurisdictional electric utilities must file DSM plans on July 1, 2010, 2013, 2016, and 2019, with annual updates in the interim periods. The IURC requires that certain core programs be established and administered by an independent third party. The IURC did not make any specific findings with respect to cost recovery issues. On March 16, 2010 Northern Indiana filed a proposal for a mechanism to recover the costs associated with these energy efficiency programs, including lost revenue. In the second phase of this proceeding, Northern Indiana will file for IURC approval of its energy efficiency programs.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

MISO. As part of Northern Indiana’s participation in the MISO transmission service, wholesale energy and ancillary service markets, certain administrative fees and non-fuel costs have been incurred. IURC orders have been issued authorizing the deferral for consideration in a future rate case proceeding of certain non-fuel related costs incurred after Northern Indiana’s rate moratorium, which expired on July 31, 2006. In its pending base rate case, Northern Indiana proposes recovery of the cumulative amount of net non-fuel charges that were deferred as of December 31, 2008, and to recover, through a tracker, charges deferred between December 31, 2008 and the date of effective rates in this case. During the first quarter of 2010, MISO costs of $1.9 million were deferred, while net credits of $0.9 million were deferred in the first quarter of 2009. As of March 31, 2010, Northern Indiana has deferred a total of $28.3 million of MISO costs.

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 the original Order would have entitled Northern Indiana 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.

MISO and PJM Interconnection undertook a joint effort in April and May 2009 to identify a source of unaccounted for flows on several coordinated flowgates. The analysis found that certain PJM Interconnection generating units that were once associated with unit-specific capacity sales were erroneously excluded from PJM Interconnection’s market flows, which significantly affected the congestion price on reciprocally coordinated flowgates on Northern Indiana systems. Higher PJM Interconnection market flows on congested flowgates would have resulted in higher payments to MISO by PJM Interconnection during market to market coordination since April 1, 2005. The model was fixed on June 18, 2009 and MISO and PJM Interconnection are currently in settlement discussions with the FERC that began on October 19, 2009 to determine the financial impact of any resettlements. Initial amounts calculated by PJM Interconnection approximated $78 million, while MISO has performed a preliminary estimate of $125 to $150 million. The impact to Northern Indiana cannot be reasonably estimated until a settlement is reached between MISO and PJM Interconnection, and MISO receives approval from the FERC on an allocation methodology to its market participants. Any adjustment will be neutral or favorable to operations.

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

On May 28, 2008, the IURC issued an order 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. On February 18, 2009, the IURC issued an order approving a settlement agreement filed in this proceeding allowing Northern Indiana to begin deferring carrying costs and depreciation, pending inclusion in rates, on Sugar Creek effective on December 1, 2008, when Sugar Creek was dispatched into MISO, at the agreed to carrying cost rate of 6.5%. The annual deferral for Sugar Creek is reduced by the annual depreciation on the Mitchell plant of $4.5 million, pursuant to the FAC-71 settlement. The terms of recovery of the deferral and inclusion of Sugar Creek in rates will be resolved in Northern Indiana’s current rate proceeding.

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. 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. During the first quarters of 2010 and 2009, the amount of purchased power costs exceeding the benchmark amounted to $0.1 million and $0.8 million, respectively, which was recognized as a net reduction of revenues.

Northern Indiana has approval from the IURC to recover certain environmental related costs through an ECT. Under the ECT, Northern Indiana is permitted to recover (1) AFUDC and a return on the capital investment expended by Northern Indiana to implement IDEM’s NOx SIP and CAIR and CAMR compliance plan projects through an ECRM and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational through an EERM. Northern Indiana anticipates a total capital investment of approximately $368 million. This revised cost estimate is subject to and pending approval by the IURC. On April 30, 2010, the IURC approved ECR-15 for recovery of items described above based upon a capital expenditure level (net of accumulated depreciation) of $287.4 million.

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. 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 or sell natural gas or power. Certain forward physical contracts are derivatives which qualify for the normal purchase and normal sales exception which would not require mark-to-market accounting.

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

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 and normal sales exception, a contract’s fair value is not recognized in the Consolidated Financial Statements until the contract is settled.

Unrealized and realized gains and losses are recognized each period as components of 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 paid to customers 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 or sales by economically hedging the various gas cost components by using a combination of futures, options, forward physical contracts, basis swap contracts or other derivative contracts. Northern Indiana also uses derivative contracts to minimize risk associated with power price volatility. These commodity price risk programs and their respective accounting treatment are described below.

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

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

Northern Indiana offers a DependaBill program to its customers as an alternative to the standard tariff rate that is charged to residential customers. This 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, and NYMEX options are used to secure forward gas prices. The normal purchase and normal sales exception is elected for forward physical contracts associated with these programs whereby delivery of the commodity is probable to occur.

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

Columbia of Kentucky, Columbia of Ohio, 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 based on the regulatory customer sharing mechanisms in place, with the remaining changes in fair value recognized currently in earnings.

As part of the MISO Day 2 initiative, Northern Indiana was allocated or has purchased FTRs. These FTRs help Northern Indiana offset congestion costs due to the MISO Day 2 activity. The FTRs are marked to fair value and are not accounted for as a hedge, but since congestion costs are recoverable through the fuel cost recovery mechanism, the related gains and losses associated with marking these derivatives to market are recorded as a regulatory asset or liability. In the second quarter of 2008, MISO changed its allocation procedures from an allocation of FTRs to an allocation of ARRs, whereby Northern Indiana was allocated ARRs based on its historical use of the MISO administered transmission system. ARRs entitle the holder to a stream of revenues or charges based on the price of the associated FTR in the FTR auction. ARRs are not derivatives and are convertible to FTRs. Northern Indiana purchased FTRs in the second quarter of 2009 and expects to purchase additional FTRs in the second quarter of 2010.

NiSource is in the process of winding down its unregulated natural gas marketing business, where gas derivatives are utilized to hedge expected future gas purchases and sales. Prior to the decision to wind down this business in the second quarter of 2009, the financial derivatives associated with commercial and industrial gas sales were 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 that have generally qualified for the normal purchase and normal sales exception, which NiSource had elected prior to the decision to wind down the business in 2009. As a result of the decision to wind down the business in the second quarter of 2009, certain forecasted transactions were 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 normal 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 recognized in income. NiSource established reserves of $9.2 million at December 31, 2009 and $9.7 million at March 31, 2010, against certain of these physical sale contract derivatives. These amounts represent reserves related to the creditworthiness of certain customers, the fair value of future cash flows, and the cost of maintaining significant amounts of restricted cash. The physical sales contracts marked-to-market had a fair value of approximately $168.5 million at March 31, 2010, while the financial derivative contracts marked-to-market had a fair value loss of $152.3 million at March 31, 2010.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

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

		March 31, 2010				December 31, 2009
Commodity Price Risk Program:
Gas price volatility program derivatives (MMDth)			24.0				26.4
Price Protection Service program derivatives (MMDth)			0.7				1.6
DependaBill program derivatives (MMDth)			0.2				0.6
Regulatory incentive program derivatives (MMDth)			5.7				1.7
Gas marketing program derivatives (MMDth) (a)			64.5				74.7
Gas marketing forward physical derivatives (MMDth) (b)			64.9				79.6
Electric energy program FTR derivatives (mw)			561.3				1,343.7

(a)		Basis contract volumes not included in the above table were 67.4 MMDth and 82.3 MMDth as of March 31, 2010 and December 31, 2009, respectively.
(b)		Basis contract volumes not included in the above table were 70.0 MMDth and 85.4 MMDth as of March 31, 2010 and December 31, 2009, respectively.

Interest Rate Risk Activities. NiSource recognizes that the prudent and selective use of derivatives may help it to lower its cost of debt capital and manage its interest rate exposure. NiSource Finance has entered into various “receive fixed” and “pay floating” interest rate swap agreements which modify the interest rate characteristics of its outstanding long-term debt from fixed to variable rate. These interest rate swaps also serve to hedge the fair market value of NiSource Finance’s outstanding debt portfolio. As of March 31, 2010, NiSource had $7.1 billion of outstanding debt, of which $1,050 million is subject to fluctuations in interest rates as a result of the fixed-to-variable interest rate swap transactions. These interest rate swaps are designated as fair value hedges. NiSource had no net gain or loss recognized in earnings due to hedging ineffectiveness.

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. 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.

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.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

Contemporaneously with the issuance on September 16, 2005 of $1 billion of its 5.25% and 5.45% notes, NiSource Finance settled $900 million of forward starting interest rate swap agreements with six counterparties. NiSource paid an aggregate settlement payment of $35.5 million which is being amortized from accumulated other comprehensive loss to interest expense over the term of the underlying debt, resulting in an effective interest rate of 5.67% and 5.88%, respectively. As of March 31, 2010, accumulated other comprehensive loss includes $14.0 million related to forward starting interest rate swap settlement. These derivative contracts are accounted for as a cash flow hedge.

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

		March 31,				December 31,
Asset Derivatives (in millions)		2010				2009
Balance Sheet Location		Fair Value				Fair Value
Derivatives designated as hedging instruments
Commodity price risk programs
Price risk management assets (current)		$	-			$	-
Price risk management assets (noncurrent)			-				-
Interest rate risk activities
Price risk management assets (noncurrent)			70.8				68.2
Total derivatives designated as hedging instruments		$	70.8			$	68.2
Derivatives not designated as hedging instruments
Commodity price risk programs
Price risk management assets (current)		$	190.4			$	173.3
Price risk management assets (noncurrent)			200.5				169.4
Total derivatives not designated as hedging instruments		$	390.9			$	342.7
Total Asset Derivatives		$	461.7			$	410.9
		March 31,				December 31,
Liability Derivatives (in millions)		2010				2009
Balance Sheet Location		Fair Value				Fair Value
Derivatives designated as hedging instruments
Commodity price risk programs
Price risk management liabilities (current)		$	1.3			$	1.0
Price risk management liabilities (noncurrent)			0.2				0.5
Total derivatives designated as hedging instruments		$	1.5			$	1.5
Derivatives not designated as hedging instruments
Commodity price risk programs
Price risk management liabilities (current)		$	209.8			$	189.1
Price risk management liabilities (noncurrent)			200.4				169.7
Total derivatives not designated as hedging instruments		$	410.2			$	358.8
Total Liability Derivatives		$	411.7			$	360.3

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 (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
		Portion)								Reclassified from AOCI		Portion)
Derivatives in Cash Flow		March 31,				March 31,				into Income (Effective		March 31,				March 31,
Hedging Relationships		2010				2009				Portion)		2010				2009
Commodity price risk programs		$	(3.3	)		$	(14.9	)		Cost of Sales		$	0.5			$	(43.8	)
Interest rate risk activities			0.4				0.4			Interest expense, net			-				(0.4	)
Total		$	(2.9	)		$	(14.5	)				$	0.5			$	(44.2	)

Three Months Ended, (in millions)

				Amount of Gain (Loss) Recognized
				in Income of Derivative
		Location of Gain (Loss)		(Ineffective Portion and Amount
		Recognized in Income on		Excluded from Effectiveness
		Derivative (Ineffective Portion		Testing)
Derivatives in Cash Flow Hedging		and Amount Excluded from
Relationships		Effectiveness Testing)		March 31, 2010				March 31, 2009
Commodity price risk programs		Cost of Sales		$	-			$	-
Interest rate risk activities		Interest expense, net			-				-
Total				$	-			$	-

Derivatives in Fair Value Hedging Relationships

Three Months Ended, (in millions)

				Amount of Gain (Loss) Recognized
Derivatives in Fair Value Hedging		Location of Gain (Loss) Recognized in		in Income on Derivatives
Relationships		Income on Derivatives		March 31, 2010				March 31, 2009
Interest rate risk activities		Interest expense, net		$	2.1			$	(3.7	)
Total				$	2.1			$	(3.7	)

Three Months Ended, (in millions)

				Amount of Gain (Loss) Recognized
Hedged Item in Fair Value Hedge		Location of Gain (Loss) Recognized in		in Income on Related Hedged Items
Relationships		Income on Related Hedged Item		March 31, 2010				March 31, 2009
Fixed-rate debt		Interest expense, net		$	(2.1	)		$	3.7
Total				$	(2.1	)		$	3.7

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

Derivatives not designated as hedging instruments

Three Months Ended, (in millions)

				Amount of Realized/Unrealized Gain
				(Loss) Recognized in Income on
				Derivatives *
Derivatives Not Designated as Hedging		Location of Gain (Loss) Recognized in
Instruments		Income on Derivatives		March 31, 2010				March 31, 2009
Commodity price risk programs		Gas Distribution revenues		$	(21.0	)		$	(48.2	)
Commodity price risk programs		Other revenues			77.2				-
Commodity price risk programs		Cost of Sales			(71.2	)			(1.4	)
Total				$	(15.0	)		$	(49.6	)

* For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed in the table above, losses of $20.7 million and $50.0 million for the first quarter of 2010 and 2009, respectively, were deferred as allowed by regulatory orders. These amounts will be amortized to income over future periods of up to twelve months as specified in a regulatory order.

During the first quarters of 2010 and 2009, no amounts were reclassified related to NiSource’s cash flow hedges from accumulated other comprehensive income (loss) to Cost of Sales due to the probability that certain forecasted transactions would not occur. It is anticipated that during the next twelve months the expiration and settlement of cash flow hedge contracts will result in income statement recognition of amounts currently classified in accumulated other comprehensive income (loss) of approximately $0.9 million of loss, net of taxes.

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

Certain NiSource affiliates have physical commodity purchase agreements that meet the definition of a derivative for which NiSource has elected the normal purchase and normal sale exception. These agreements are exempt from the requirements of Derivatives and Hedging Accounting, and are not measured at fair value. Certain of these agreements do contain “ratings triggers” that require increases in collateral if the credit rating of NiSource or certain of its affiliates are rated below BBB- by Standard and Poor’s or below Baa3 by Moody’s. As of March 31, 2010, there were no accounts payables under physical commodity purchase agreements containing ratings triggers.

NiSource had $218.3 million and $173.2 million of cash on deposit with brokers for margin requirements associated with open derivative positions reflected within, “Restricted cash,” on the Condensed Consolidated Balance Sheets (unaudited) as of March 31, 2010 and December 31, 2009, respectively.

10.         Fair Value Disclosures

A.          Fair Value Measurements. NiSource adopted the provisions of ASC Topic 820 – Fair Value Measurements and Disclosures for financial assets and liabilities on January 1, 2008 and non-financial assets and liabilities on January 1, 2009. There was no impact on retained earnings as a result of the adoption.

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on NiSource’s Consolidated Balance Sheet on a recurring basis and their level within the fair value hierarchy as of March 31, 2010 and December 31, 2009:

		Quoted Prices in				Significant
		Active Markets				Other				Significant
		for Identical				Observable				Unobservable
Recurring Fair Value Measurements		Assets				Inputs				Inputs				Balance as of
March 31, 2010 (in millions)		(Level 1)				(Level 2)				(Level 3)				March 31, 2010
Assets
Commodity Price risk management assets:
Physical price risk programs		$	-			$	179.1			$	-			$	179.1
Financial price risk programs			205.5				5.3				-				210.8
Other			-				-				1.0				1.0
Interest rate risk activities			-				70.8				-				70.8
Available-for-sale securities			35.4				35.9				-				71.3
Total		$	240.9			$	291.1			$	1.0			$	533.0
Liabilities
Commodity Price risk management liabilities:
Physical price risk programs		$	-			$	4.7			$	-			$	4.7
Financial price risk programs			401.3				5.5				-				406.8
Other			-				-				0.2				0.2
Total		$	401.3			$	10.2			$	0.2			$	411.7

		Quoted Prices in				Significant
		Active Markets				Other				Significant
		for Identical				Observable				Unobservable
Recurring Fair Value Measurements		Assets				Inputs				Inputs				Balance as of
December 31, 2009 (in millions)		(Level 1)				(Level 2)				(Level 3)				December 31, 2009
Assets
Commodity Price risk management assets:
Physical price risk programs		$	-			$	141.7			$	-			$	141.7
Financial price risk programs			187.5				11.4				-				198.9
Other			-				-				2.1				2.1
Interest rate risk activities			-				68.2				-				68.2
Available-for-sale securities			34.5				37.4				-				71.9
Total		$	222.0			$	258.7			$	2.1			$	482.8
Liabilities
Commodity Price risk management liabilities:
Physical price risk programs		$	-			$	9.6			$	-			$	9.6
Financial price risk programs			343.8				6.9				-				350.7
Total		$	343.8			$	16.5			$	-			$	360.3

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

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

To determine the fair value of derivatives associated with NiSource’s unregulated natural gas marketing business, certain reserves were calculated. These reserves were primarily determined by evaluating the credit worthiness of certain customers, fair value of future cash flows, and the cost of maintaining restricted cash. Refer to Note 9, “Risk Management Activities” for additional information on price risk assets.

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

Available-for-sale securities are investments pledged as collateral for trust accounts related to NiSource’s wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). Securities classified within Level 1 include U.S. Treasury debt securities which are highly liquid and are actively traded in over-the-counter markets. NiSource values corporate and mortgage-backed debt securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2. Unrealized gains and losses from available-for-sale securities are included in other comprehensive income (loss). The amortized cost, gross unrealized gains and losses, and fair value of available-for-sale debt securities at March 31, 2010 and December 31, 2009 were:

										Gross
						Gross Unrealized				Unrealized
(in millions)		Amortized Cost				Gains				Losses				Fair Value
Available-for-sale debt securities, March 31, 2010
U.S. Treasury securities		$	35.4			$	0.2			$	(0.2	)		$	35.4
Corporate/Other bonds			33.8				2.1				-				35.9
Total Available-for-sale debt securities		$	69.2			$	2.3			$	(0.2	)		$	71.3
										Gross
						Gross Unrealized				Unrealized
(in millions)		Amortized Cost				Gains				Losses				Fair Value
Available-for-sale debt securities, December 31, 2009
U.S. Treasury securities		$	34.6			$	0.2			$	(0.3	)		$	34.5
Corporate/Other bonds			35.2				2.2				-				37.4
Total Available-for-sale debt securities		$	69.8			$	2.4			$	(0.3	)		$	71.9

ITEM 1.  FINANCIAL STATEMENTS (continued)

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

For the three months ended March 31, 2010 and 2009 the realized gain on sale of available for sale U.S. Treasury debt securities was zero and $0.9 million, respectively. For the three months ended March 31, 2010 and 2009 the realized gain on sale of available for sale Corporate/Other bond debt securities was $0.4 million and zero, respectively. The cost of maturities sold is based upon specific identification. At March 31, 2010, all U.S. Treasury debt securities have maturities of greater than one year. At March 31, 2010, approximately $2.0 million of Corporate/Other bonds have maturities of less than a year while the remaining securities have maturities of greater than one year.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the periods ended March 31, 2010 and 2009:

		Financial
Period Ended March 31, 2010 (in millions)		Transmission Rights				Other Derivatives				Total
Balance as of January 1, 2010		$	1.9			$	0.2			$	2.1
Total gains or (losses) (unrealized/realized)
Included in regulatory assets/liabilities			-				-				-
Purchases, issuances and settlements (net)			(1.0	)			(0.3	)			(1.3	)
Balance as of March 31, 2010		$	0.9			$	(0.1	)		$	0.8
Change in unrealized gains/(losses) relating to instruments still held as of March 31, 2010		$	-			$	-			$	-
		Financial
Period Ended March 31, 2009 (in millions)		Transmission Rights				Other Derivatives				Total
Balance as of January 1, 2009		$	2.6			$	1.6			$	4.2
Total gains or losses (unrealized/realized)
Included in regulatory assets/liabilities			-				0.2				0.2
Purchases, issuances and settlements (net)			(1.7	)			(2.0	)			(3.7	)
Balance as of March 31, 2009		$	0.9			$	(0.2	)		$	0.7
Change in unrealized gains/(losses) relating to instruments still held as of March 31, 2009		$	-			$	0.2			$	0.2