NISOURCE INC. - Quarter Report: 2011 June (Form 10-Q)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

NiSource Inc.

(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 þ No o

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Stock, $0.01 Par Value: 280,613,617 shares outstanding at July 29, 2011.

 

 

NISOURCE INC.
FORM 10-Q QUARTERLY REPORT
FOR THE QUARTER ENDED June 30, 2011

Table of Contents

		Page
Defined Terms			3
PART I FINANCIAL INFORMATION
Item 1. Financial Statements — unaudited
Condensed Statements of Consolidated Income (unaudited)			6
Condensed Consolidated Balance Sheets (unaudited)			7
Condensed Statements of Consolidated Cash Flows (unaudited)			9
Condensed Statements of Consolidated Comprehensive Income (unaudited)			10
Notes to Condensed Consolidated Financial Statements (unaudited)			11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			50
Item 3. Quantitative and Qualitative Disclosures About Market Risk			74
Item 4. Controls and Procedures			74
PART II OTHER INFORMATION
Item 1. Legal Proceedings			75
Item 1A. Risk Factors			76
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			76
Item 3. Defaults Upon Senior Securities			76
Item 4. (Removed and Reserved)			76
Item 5. Other Information			76
Item 6. Exhibits			77
Signature			78
EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

DEFINED TERMS

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

NiSource Subsidiaries and Affiliates
Capital Markets		NiSource Capital Markets, Inc.
CER		Columbia Energy Resources, Inc.
CGORC		Columbia Gas of Ohio Receivables Corporation
CNR		Columbia Natural Resources, Inc.
Columbia		Columbia Energy Group
Columbia Gulf		Columbia Gulf Transmission Company
Columbia of Kentucky		Columbia Gas of Kentucky, Inc.
Columbia of Maryland		Columbia Gas of Maryland, Inc.
Columbia of Massachusetts		Bay State Gas Company
Columbia of Ohio		Columbia Gas of Ohio, Inc.
Columbia of Pennsylvania		Columbia Gas of Pennsylvania, Inc.
Columbia of Virginia		Columbia Gas of Virginia, Inc.
Columbia Transmission		Columbia Gas Transmission, L.L.C.
CPRC		Columbia Gas of Pennsylvania Receivables Corporation
Crossroads Pipeline		Crossroads Pipeline Company
Granite State Gas		Granite State Gas Transmission, Inc.
Hardy Storage		Hardy Storage Company, L.L.C.
Kokomo Gas		Kokomo Gas and Fuel Company
Millennium		Millennium Pipeline Company, L.L.C.
NARC		NIPSCO Accounts Receivable Corporation
NDC Douglas Properties		NDC Douglas Properties, Inc.
NiSource		NiSource Inc.
NiSource Corporate Services		NiSource Corporate Services Company
NiSource Development Company		NiSource Development Company, Inc.
NiSource Finance		NiSource Finance Corp.
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
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.
BTU		British Thermal Unit
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.
CSAPR		Cross-State Air Pollution Rule

DEFINED TERMS

Day 2		Began April 1, 2005 and refers to the operational control of the energy markets by MISO, including the dispatching of wholesale electricity and generation, managing transmission constraints, and managing the day-ahead, real-time and financial transmission rights markets
DPU		Department of Public Utilities
DSM		Demand Side Management
Dth		Dekatherm
ECRM		Environmental Cost Recovery Mechanism
ECT		Environmental Cost Tracker
EERM		Environmental Expense Recovery Mechanism
EPA		United States Environmental Protection Agency
EPS		Earnings per share
FAC		Fuel adjustment clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
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
NSR		New Source Review
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income (Loss)
OPEB		Other Postretirement and Postemployment Benefits
OUCC		Indiana Office of Utility Consumer Counselor
PADEP		Pennsylvania Department of Environmental Protection
Piedmont		Piedmont Natural Gas Company, Inc.
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
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
RTO		Regional Transmission Organization
SEC		Securities and Exchange Commission
SIP		State Implementation Plan
SO2		Sulfur dioxide

DEFINED TERMS

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								Six Months Ended
		June 30,								June 30,
(in millions, except per share amounts)		2011				2010				2011				2010
Net Revenues
Gas Distribution		$	500.4			$	454.3			$	1,872.4			$	1,795.4
Gas Transportation and Storage			307.3				264.3				710.3				634.8
Electric			349.2				340.5				696.3				658.4
Other			71.4				112.0				181.5				441.2
Gross Revenues			1,228.3				1,171.1				3,460.5				3,529.8
Cost of Sales (excluding depreciation and amortization)			462.5				439.1				1,633.4				1,725.4
Total Net Revenues			765.8				732.0				1,827.1				1,804.4
Operating Expenses
Operation and maintenance			402.5				377.1				835.0				816.7
Depreciation and amortization			134.5				151.6				273.4				301.4
Impairment and loss on sale of assets, net			—				—				0.7				0.1
Other taxes			67.8				64.5				160.8				151.4
Total Operating Expenses			604.8				593.2				1,269.9				1,269.6
Equity Earnings in Unconsolidated Affiliates			2.3				0.4				5.3				7.8
Operating Income			163.3				139.2				562.5				542.6
Other Income (Deductions)
Interest expense, net			(94.4	)			(98.4	)			(184.2	)			(197.2	)
Other, net			0.6				2.6				3.9				5.2
Total Other Deductions			(93.8	)			(95.8	)			(180.3	)			(192.0	)
Income from Continuing Operations before Income Taxes			69.5				43.4				382.2				350.6
Income Tax Expense			30.0				15.4				137.9				125.2
Income from Continuing Operations			39.5				28.0				244.3				225.4
(Loss)/Income from Discontinued Operations — net of taxes			(0.6	)			0.1				(0.2	)			(0.1	)
Gain on Disposition of Discontinued Operations — net of taxes			—				—				—				0.1
Net Income		$	38.9			$	28.1			$	244.1			$	225.4
Basic Earnings Per Share
Continuing operations		$	0.14			$	0.10			$	0.87			$	0.81
Discontinued operations			—				—				—				—
Basic Earnings Per Share		$	0.14			$	0.10			$	0.87			$	0.81
Diluted Earnings Per Share
Continuing operations		$	0.14			$	0.10			$	0.85			$	0.81
Discontinued operations			—				—				—				—
Diluted Earnings Per Share		$	0.14			$	0.10			$	0.85			$	0.81
Dividends Declared Per Common Share		$	0.23			$	0.23			$	0.69			$	0.69
Basic Average Common Shares Outstanding			280.2				277.6				279.8				277.3
Diluted Average Common Shares			287.1				278.4				286.2				278.0

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

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

		June 30,				December 31,
(in millions)		2011				2010
ASSETS
Property, Plant and Equipment
Utility Plant		$	19,783.8			$	19,494.9
Accumulated depreciation and amortization			(8,602.9	)			(8,492.6	)
Net utility plant			11,180.9				11,002.3
Other property, at cost, less accumulated depreciation			114.1				94.7
Net Property, Plant and Equipment			11,295.0				11,097.0
Investments and Other Assets
Assets of discontinued operations and assets held for sale			2.3				7.9
Unconsolidated affiliates			197.2				200.9
Other investments			150.8				139.7
Total Investments and Other Assets			350.3				348.5
Current Assets
Cash and cash equivalents			59.9				9.2
Restricted cash			154.6				202.9
Accounts receivable (less reserve of $42.0 and $37.4, respectively)			638.3				1,079.3
Income tax receivable			1.2				99.0
Gas inventory			278.0				298.2
Underrecovered gas and fuel costs			24.7				135.7
Materials and supplies, at average cost			87.0				83.8
Electric production fuel, at average cost			44.9				46.0
Price risk management assets			116.0				159.5
Exchange gas receivable			118.2				62.7
Regulatory assets			121.9				151.8
Prepayments and other			100.4				120.8
Total Current Assets			1,745.1				2,448.9
Other Assets
Price risk management assets			190.6				240.3
Regulatory assets			1,622.2				1,650.4
Goodwill			3,677.3				3,677.3
Intangible assets			303.1				308.6
Postretirement and postemployment benefits assets			42.0				35.1
Deferred charges and other			120.7				132.7
Total Other Assets			5,955.9				6,044.4
Total Assets		$	19,346.3			$	19,938.8

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)

		June 30,				December 31,
(in millions, except share amounts)		2011				2010
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stockholders’ Equity
Common stock — $0.01 par value, 400,000,000 shares authorized; 280,472,662 and 278,855,291 shares issued and outstanding, respectively		$	2.8			$	2.8
Additional paid-in capital			4,132.9				4,103.9
Retained earnings			952.6				901.8
Accumulated other comprehensive loss			(54.5	)			(57.9	)
Treasury stock			(30.4	)			(27.4	)
Total Common Stockholders’ Equity			5,003.4				4,923.2
Long-term debt, excluding amounts due within one year			6,340.0				5,936.1
Total Capitalization			11,343.4				10,859.3
Current Liabilities
Current portion of long-term debt			30.0				34.2
Short-term borrowings			870.4				1,382.5
Accounts payable			316.2				581.8
Dividends payable			64.6				0.1
Customer deposits and credits			183.1				318.1
Taxes accrued			179.5				221.1
Interest accrued			114.4				114.4
Overrecovered gas and fuel costs			121.4				11.8
Price risk management liabilities			135.0				173.9
Exchange gas payable			155.4				266.1
Deferred revenue			5.0				6.8
Regulatory liabilities			83.5				92.9
Accrued liability for postretirement and postemployment benefits			23.3				23.3
Temporary LIFO liquidation credit			0.3				—
Legal and environmental reserves			46.0				86.0
Other accruals			230.0				336.4
Total Current Liabilities			2,558.1				3,649.4
Other Liabilities and Deferred Credits
Price risk management liabilities			127.8				181.6
Deferred income taxes			2,369.1				2,209.7
Deferred investment tax credits			31.3				33.7
Deferred credits			75.5				68.6
Deferred revenue			—				0.3
Accrued liability for postretirement and postemployment benefits			919.6				1,039.6
Regulatory liabilities and other removal costs			1,624.8				1,595.8
Asset retirement obligations			138.9				138.8
Other noncurrent liabilities			157.8				162.0
Total Other Liabilities and Deferred Credits			5,444.8				5,430.1
Commitments and Contingencies (Refer to Note 19)			—				—
Total Capitalization and Liabilities		$	19,346.3			$	19,938.8

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

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Six Months Ended June 30, (in millions)		2011				2010
Operating Activities
Net Income		$	244.1			$	225.4
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Depreciation and amortization			273.4				301.4
Net changes in price risk management assets and liabilities			15.3				4.4
Deferred income taxes and investment tax credits			132.1				38.6
Deferred revenue			(2.6	)			(17.2	)
Stock compensation expense and 401(k) profit sharing contribution			17.2				6.0
Loss on sale of assets			—				0.1
Loss on impairment of assets			0.7				—
Income from unconsolidated affiliates			(4.4	)			(7.8	)
Gain on disposition of discontinued operations — net of taxes			—				(0.1	)
Loss from discontinued operations — net of taxes			0.2				0.1
Amortization of debt related costs			4.2				5.4
AFUDC equity			(1.9	)			(3.7	)
Distributions of earnings received from equity investee			9.9				7.9
Changes in Assets and Liabilities:
Accounts receivable			434.6				245.1
Income tax receivable			97.8				24.8
Inventories			13.7				147.6
Accounts payable			(250.4	)			(235.4	)
Customer deposits and credits			(134.9	)			(104.7	)
Taxes accrued			(40.7	)			6.2
Interest accrued			—				5.3
Over (Under) recovered gas and fuel costs			220.7				(252.3	)
Exchange gas receivable/payable			(166.2	)			(51.3	)
Other accruals			(26.3	)			(30.5	)
Prepayments and other current assets			20.6				28.1
Regulatory assets/liabilities			28.3				98.3
Postretirement and postemployment benefits			(118.9	)			1.7
Deferred credits			6.3				(3.6	)
Deferred charges and other noncurrent assets			12.1				4.6
Other noncurrent liabilities			(4.8	)			2.9
Net Operating Activities from Continuing Operations			780.1				447.3
Net Operating Activities used for Discontinued Operations			(44.1	)			(44.8	)
Net Cash Flows from Operating Activities			736.0				402.5
Investing Activities
Capital expenditures			(445.0	)			(336.9	)
Insurance recoveries			—				0.5
Proceeds from disposition of assets			9.4				0.3
Restricted cash withdrawals (deposits)			48.3				(38.0	)
Contributions to equity investees			(0.1	)			(0.3	)
Other investing activities			(36.0	)			(19.9	)
Net Investing Activities used for Continuing Operations			(423.4	)			(394.3	)
Net Investing Activities from Discontinued Operations			—				0.4
Net Cash Flow used for Investing Activities			(423.4	)			(393.9	)
Financing Activities
Issuance of long-term debt			395.3				—
Retirement of long-term debt			(13.0	)			(5.2	)
Premiums and other debt related costs			(8.2	)			—
Change in short-term borrowings, net			(512.2	)			109.8
Issuance of common stock			7.9				6.8
Acquisition of treasury stock			(3.0	)			(1.4	)
Dividends paid — common stock			(128.7	)			(127.6	)
Net Cash Flow used for Financing Activities			(261.9	)			(17.6	)
Change in cash and cash equivalents from continuing operations			94.8				35.4
Cash contributions to discontinued operations			(44.1	)			(44.4	)
Cash and cash equivalents at beginning of period			9.2				16.4
Cash and Cash Equivalents at End of Period		$	59.9			$	7.4

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								Six Months Ended
		June 30,								June 30,
(in millions, net of taxes)		2011				2010				2011				2010
Net Income		$	38.9			$	28.1			$	244.1			$	225.4
Other comprehensive income (loss)
Net unrealized gain (loss) on available-for-sale securities(a)			1.1				(0.1	)			0.9				0.4
Net unrealized gain (loss) on cash flow hedges(b),(c)			0.6				(10.4	)			1.7				(13.3	)
Unrecognized pension benefit and OPEB costs(d)			0.4				0.5				0.8				(1.6	)
Total other comprehensive income (loss)			2.1				(10.0	)			3.4				(14.5	)
Total Comprehensive Income		$	41.0			$	18.1			$	247.5			$	210.9

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, 2010. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

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

2. Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Fair Value Measurements and Disclosures. In January 2010, the FASB issued authoritative guidance that amends the disclosures about transfers into and out of Levels 1 and 2 and requires separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. This guidance also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. This guidance is effective for the first reporting period, including interim periods, beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which is effective for fiscal years beginning after December 15, 2010. Early adoption is permitted. NiSource adopted the guidance on January 1, 2010 with the exception of the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis. The guidance pertaining to the gross presentation of Level 3 activity was adopted on January 1, 2011. Refer to Note 10, “Fair Value Disclosures,” for additional information.

Recently Issued Accounting Pronouncements

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

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 and the Forward Agreements (refer to Note 4 “Forward Equity Agreement” for additional information). The calculation of diluted earnings per share for June 30, 2011 and 2010 excludes out-of-the-money stock options that had an anti-dilutive effect. The numerator in calculating both basic and diluted EPS for each period is reported net income. The computation of diluted average common shares follows:

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2011				2010				2011				2010
Denominator
Basic average common shares outstanding			280,217				277,566				279,780				277,258
Dilutive potential common shares
Shares contingently issuable under employee stock plans			1,078				300				1,061				300
Shares restricted under employee stock plans			342				511				326				480
Forward Agreements			5,422				—				4,989				—
Diluted Average Common Shares			287,059				278,377				286,156				278,038

4. Forward Equity Agreement

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

In connection with the public offering, NiSource entered into forward sale agreements (“Forward Agreements”) with an affiliate of the forward seller covering an aggregate of 24,265,000 shares of NiSource’s common stock. Settlement of the Forward Agreements is expected to occur no later than September 10, 2012. Subject to certain exceptions, NiSource may elect cash or net share settlement for all or a portion of its obligations under the Forward Agreements. Upon any physical settlement of the Forward Agreements, NiSource will deliver shares of its common stock in exchange for cash proceeds at the forward sale price, which initially is $15.9638 and is subject to adjustment as provided in the Forward Agreements. If the equity forward had been settled by delivery of shares at June 30, 2011, NiSource would have received approximately $369.3 million based on a forward price of $15.2204 for the 24,265,000 shares. NiSource currently anticipates settling the equity forward by delivering shares.

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

5. Gas in Storage

Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural 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. NiSource has a temporary LIFO liquidation debit of $6.8 million recorded for the first six months of 2011 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 of discontinued operations and held for sale on the Condensed Consolidated Balance Sheet (unaudited) at June 30, 2011 were:

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

(in millions)

		Property, plant and
Assets of discontinued operations and held for sale:		equipment, net				Other assets				Total
Columbia Transmission		$	2.3			$	—			$	2.3
Total		$	2.3			$	—			$	2.3

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

The assets of discontinued operations and held for sale on the Consolidated Balance Sheet at December 31, 2010 were:

(in millions)

		Property, plant and
Assets of discontinued operations and held for sale:		equipment, net				Other assets				Total
NiSource Corporate Services		$	5.6			$	—			$	5.6
Columbia Transmission			2.3				—				2.3
Total		$	7.9			$	—			$	7.9

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

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

On June 18, 2009, Columbia Transmission received approval from the FERC to abandon certain natural gas pipeline facilities by sale of its Line R System in West Virginia. Assets held for sale related to the Line R System have a net book value of $2.1 million. The sales transaction is expected to close in the fourth quarter of 2011.

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

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in millions)		2011				2010				2011				2010
Revenues from Discontinued Operations		$	—			$	—			$	—			$	0.7
(Loss) Income from discontinued operations			(0.8	)			0.2				(0.2	)			(0.1	)
Income tax (benefit) expense			(0.2	)			0.1				—				—
(Loss) Income from Discontinued Operations — net of taxes		$	(0.6	)		$	0.1			$	(0.2	)		$	(0.1	)
Gain on Disposition of Discontinued Operations — net of taxes		$	—			$	—			$	—			$	0.1

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 six months of 2011 and 2010 are presented in the table below:

(in millions)		2011				2010
Balance as of January 1,		$	138.8			$	138.2
Accretion expense			0.3				0.4
Accretion recorded as a regulatory asset/liability			3.8				3.7
Settlements			(1.1	)			(5.5	)
Change in estimated cash flows			(2.9	)			—
Balance as of June 30,		$	138.9			$	136.8

8. Regulatory Matters

Gas Distribution Operations Regulatory Matters

Significant Rate Developments. On June 1, 2011, Columbia of Virginia filed an application for approval of an infrastructure tracking mechanism pursuant to the Steps to Advance Virginia’s Energy (“SAVE”) Plan Act. Columbia of Virginia’s SAVE Plan provides for recovery of costs associated with the accelerated replacement of certain facilities designed to improve system safety or reliability through a rate rider that would commence on January 1, 2012. The proposed replacement program would result in investments of $20 million per year from 2012 through 2016, as well as covering $2.9 million in investment occurring in 2011. The VSCC issued a procedural order on June 17, 2011 providing for the filing of responsive testimony and scheduling a public hearing for September 7, 2011.

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

On January 14, 2011, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $37.8 million annually, and seeking to implement a levelized distribution charge for its residential class that would mitigate revenue volatility associated with volumetric rates. The parties jointly filed a petition for approval of a partial settlement on July 1, 2011. The partial settlement resolves all issues except Columbia of Pennsylvania’s proposed residential rate design and a challenge to the structure of one of the Company’s customer programs. Resolution of the residential rate design issue, as stated above, will impact revenue

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

volatility, while resolution of the other contested issue will be revenue neutral. The proposed settlement provides for an annual revenue increase of $17 million. Columbia of Pennsylvania expects that the Pennsylvania PUC will issue an order in October 2011 with rates also going into effect in October 2011.

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

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

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

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

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

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Northern Indiana to reduce current period gas plant depreciation expense by up to $25.7 million annually for the next four years or until further order of the IURC, whichever occurs first.

On May 3, 2010, Columbia of Virginia filed a base rate case with the VSCC seeking an annual revenue increase of $13.0 million to recover an updated level of costs upon the expiration of its Performance Based Regulation Plan on December 31, 2010. Columbia of Virginia also sought a Weather Normalization Adjustment (“WNA”), cost recovery of certain gas-related items through its Purchased Gas Adjustment (“PGA”) mechanism rather than base rates, and forward looking adjustments predicted to occur during the rate year ending December 31, 2011. On November 16, 2010, Columbia of Virginia, the VSCC Staff and the other parties filed a Proposed Stipulation and Recommendation (“Stipulation”) that would result in an annual revenue increase of $4.9 million, including authorization of the WNA and recovery of certain gas-related items through the PGA mechanism. The Chief Hearing Examiner issued a Report on December 2, 2010 recommending approval of the Stipulation. The VSCC issued a Final Order on December 17, 2010 adopting the Stipulation. New rates became effective January 1, 2011.

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

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

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

On January 30, 2009, Columbia of Ohio filed an application with the PUCO to implement a gas supply auction. The auction replaced Columbia of Ohio’s current GCR mechanism for providing commodity gas supplies to its sales customers. By order dated December 2, 2009, the PUCO approved a stipulation that resolved all issues in the case. Pursuant to the stipulation, Columbia of Ohio will conduct two consecutive one-year long standard service offer auction periods starting April 1, 2010 and April 1, 2011. On February 23, 2010, Columbia of Ohio held the first standard service offer auction which resulted in a final retail price adjustment of $1.93 per Mcf. On February 24, 2010 the PUCO issued an entry that approved the results of the auction and directed Columbia of Ohio to proceed with the implementation of the standard service offer process. On February 8, 2011, Columbia of Ohio held its second standard service offer auction which resulted in a retail price adjustment of $1.88 per Mcf. On February 9, 2011, the PUCO issued an entry that approved the results of the auction with the new retail price adjustment to

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

become effective April 1, 2011. Columbia of Ohio is scheduled to conduct its first standard choice offer auction in February 2012. Several parties have challenged the transition from a standard service offer auction to a standard choice offer auction and the PUCO conducted hearings on the matter on July 14 and July 17, 2011. Columbia of Ohio anticipates an order to be issued by the Commission in this case during the third quarter of this year.

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

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

Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as bad debt expenses. Increases in the expenses that are the subject of trackers, result in a corresponding increase in net revenues and therefore have essentially no impact on total operating income results.

Certain of the NiSource distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC’s approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.

Gas Transmission and Storage Operations Regulatory Matters

Columbia Gulf Rate Case. On October 28, 2010, Columbia Gulf filed a rate case with the FERC, proposing a rate increase and tariff changes. Among other things, the filing proposes a revenue increase of approximately $50 million to cover increases in the cost of services, which includes adjustments for operation and maintenance expenses, capital investments, adjustments to depreciation rates and expense, rate of return, and increased federal, state and local taxes. On November 30, 2010, the FERC issued an order allowing new rates to become effective by May 2011, subject to refund. Columbia Gulf placed new rates into effect, subject to refund, on May 1, 2011. Columbia Gulf and the parties to the case are actively engaged in settlement discussions to resolve the case.

Electric Operations Regulatory Matters

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

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

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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

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

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

Northern Indiana filed a petition for reconsideration with the IURC on September 14, 2010 to clarify that the effective date of certain aspects of the 2008 case including the new depreciation rates, commencement of amortization of deferred balances and discontinuance of further regulatory deferrals and the $55.0 million bill credit should coincide with the IURC’s approval of new customer rates. On October 22, 2010, the IURC issued a docket entry clarifying that this interpretation is correct.

On November 19, 2010, Northern Indiana filed a petition with the IURC for new electric base rates and charges. The filing requests an increase in base rates calculated to produce additional gross revenue of $75.7 million when compared to a normalized test year ended June 30, 2010. This is calculated to provide the opportunity to earn a return of 7.70% on net original cost rate base of $2,706 million. If approved, the rates from this new petition would replace any other existing rates, including those that may be approved by effect of the August 25, 2010 rate order. The proposed rates would ease bill impacts on residential customers, while still allowing Northern Indiana to continue investing in service, reliability and infrastructure improvements. Northern Indiana filed the proceeding under the IURC’s minimum standard filing requirements prescribing timeframes for issuance of an order if required information is supplied as part of the rate case filing. The IURC held its prehearing conference on December 17, 2010 and issued a prehearing conference order on January 5, 2011. The parties agreed to and the IURC ordered a procedural schedule that includes a bifurcated hearing. The evidentiary hearing on the revenue requirement portion of Northern Indiana’s case-in-chief was held on February 28 — March 4, 2011, and the evidentiary hearing on the cost allocation portion of the case was held the week of May 16, 2011.

On July 18, 2011, Northern Indiana filed with the IURC a collaborative settlement in its 2010 Electric Rate Case with the OUCC, Northern Indiana Industrial Group, NLMK Indiana and Indiana Municipal Utilities Group. The provisions of the stipulation and settlement agreement are subject to the review and approval of the IURC. The provisions of the settlement include a revenue requirement of $1,401 million including other revenue of $46 million for a net revenue requirement of $1,355 million from base rates. The margin, embedded in the $1,401 million revenue requirement, is $926.5 million, as compared to test year margin of $817 million. If the settlement is approved, it would terminate the current customer credit ($59 million reduction in margins during the test year) and lead to the expiration of certain industrial special contracts ($32.8 million reduction in margins during the test year). The settlement agreement will limit the proposed base rate impact to residential customers to 4.5% while also providing a solid foundation from which Northern Indiana can invest in energy infrastructure to help fuel job creation and economic growth. The parties have also agreed to a rate of return of 6.98% based upon a 10.2% return on equity. The settlement, if approved, would also resolve all pending issues related to compliance with the August 25, 2010 order in the 2008 Electric Rate Case. The settlement includes a request by the parties for the IURC to issue an order approving the settlement by December 31, 2011. A final hearing has been scheduled for September 12, 2011, through September 14, 2011.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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

During 2002, Northern Indiana settled certain regulatory matters related to an electric rate review. On September 23, 2002, the IURC issued an Order adopting most aspects of the settlement. The Order approving the settlement provides that certain electric customers of Northern Indiana will receive bill credits of approximately $55.1 million each year. The credits will continue at approximately the same annual level and per the same methodology, until the IURC approval and implementation of new customer rates. Credits amounting to $25.1 million and $29.0 million were recognized for electric customers for the first six months of 2011 and 2010, respectively.

On December 9, 2009, the IURC issued an order in its generic DSM investigation proceeding establishing an overall annual energy savings goal of 2% to be achieved by Indiana jurisdictional electric utilities in 10 years, with interim savings goals established in years one through nine. Under the order, Northern Indiana and other jurisdictional electric utilities must file DSM plans on July 1, 2010, 2013, 2016, and 2019, with annual updates in the interim periods. The IURC requires that certain core programs be established and administered by an independent third party. The IURC did not make any specific findings with respect to cost recovery issues. In compliance with the December 9, 2009 Order, on March 16, 2010 Northern Indiana filed a proposal for a mechanism to recover the costs associated with these energy efficiency programs, including lost revenue. On June 17, 2010, Northern Indiana filed for approval of its energy efficiency programs, recovery of program costs and lost revenue, and its proposed performance incentive level and methodology. On May 25, 2011, the IURC issued an order approving the mechanism to recover the costs associated with these energy efficiency programs. On July 27, 2011, the IURC issued on order approving the energy efficiency programs and recovery of program costs. However, the IURC denied lost revenue recovery at this time, and Northern Indiana may consider filing with the IURC a request for the recovery of lost revenue once rates and charges become effective in the 2010 Electric Rate Case. The IURC also approved Northern Indiana’s proposal to seek performance incentives after program results can be evaluated based upon evaluation, measurement, and verification data.

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

MISO. As part of Northern Indiana’s participation in the MISO transmission service, wholesale energy and ancillary service markets, certain administrative fees and non-fuel costs have been incurred. IURC orders have been issued authorizing the deferral for consideration in a future rate case proceeding of certain non-fuel related costs incurred after Northern Indiana’s rate moratorium, which expired on July 31, 2006. Northern Indiana proposed recovery of the cumulative amount of net non-fuel charges that were deferred as of December 31, 2008, and to recover, through a tracker, charges deferred between December 31, 2008 and the IURC’s approval of new customer rates. During the first six months of 2011 and 2010, MISO costs of $5.7 million and $4.8 million were deferred, respectively. As of June 30, 2011, Northern Indiana had deferred a total of $42.3 million of MISO costs. In the rate order issued on August 25, 2010, the IURC approved an RTO tracker for recovery of MISO non-fuel costs and revenues and off-system sales sharing and ordered that purchased power costs and fuel-related MISO charge types be recovered in the FAC. The IURC also approved a purchase capacity tracker referred to as the Resource Adequacy Tracker. The implementation of such trackers coincides with the IURC’s approval and implementation of new customer rates.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

uses derivative contracts to minimize risk associated with power price volatility. These commodity price risk programs and their respective accounting treatment are described below.

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

Northern Indiana, Columbia of Pennsylvania and Columbia of Virginia offer a fixed price program as an alternative to the standard GCR mechanism. These services provide customers with the opportunity to either lock in their gas cost or place a cap on the gas costs that would be charged in future months. In order to hedge the anticipated physical purchases associated with these obligations, forward physical contracts, NYMEX futures and NYMEX options are used to secure forward gas prices. The accounting treatment elected for these contracts is varied whereby certain of these contracts 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 where delivery of the commodity is probable to occur.

Northern Indiana also offers a DependaBill program to its customers as an alternative to the standard tariff rate that is charged to residential customers. The program allows Northern Indiana customers to fix their total monthly bill in future months at a flat rate regardless of gas usage or commodity cost. In order to hedge the anticipated physical purchases associated with these obligations, forward physical contracts, NYMEX futures and NYMEX options have been used to secure forward gas prices. The accounting treatment elected for these contracts is varied whereby certain of these contracts 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.

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

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

NiSource is in the process of winding down its unregulated natural gas marketing business, where gas financial contracts are utilized to economically hedge expected future gas purchases associated with forward gas agreements. These financial contracts, as well as the associated forward physical sales contracts, are derivatives and are

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

marked-to-market with all associated gains and losses recognized to income. NiSource established reserves of $3.8 million at June 30, 2011 and $6.4 million at December 31, 2010, against certain of these physical sale contract derivatives. These amounts represent reserves related to the creditworthiness of certain customers, the fair value of future cash flows, and the cost of maintaining significant amounts of restricted cash. The physical sales contracts marked-to-market had a fair value gain of approximately $118.1 million at June 30, 2011 and $154.4 million at December 31, 2010, while the financial derivative contracts marked-to-market had a fair value loss of $114.9 million at June 30, 2011 and $137.5 million at December 31, 2010. The $137.5 million loss at December 31, 2010 did not include approximately $10.3 million of January 2011 financial positions as these positions were settled in December 2010.

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

		June 30, 2011				December 31, 2010
Commodity Price Risk Program:
Gas price volatility program derivatives (MMDth)			31.0				28.4
Price Protection Service program derivatives (MMDth)			1.0				1.6
DependaBill program derivatives (MMDth)			0.3				0.4
Regulatory incentive program derivatives (MMDth)			4.9				2.0
Gas marketing program derivatives (MMDth)(a)			35.0				48.2
Gas marketing forward physical derivatives (MMDth)(b)			34.9				48.0
Electric energy program FTR derivatives (mw)			15,972.0				8,279.1

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, 2011, NiSource had $7.2 billion of outstanding debt, of which $500.0 million is subject to fluctuations in interest rates as a result of the fixed-to-variable interest rate swap transactions. These interest rate swaps are designated as fair value hedges. NiSource had no net gain or loss recognized in earnings due to hedging ineffectiveness.

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

Contemporaneously with the issuance on September 16, 2005 of $1 billion of its 5.25% and 5.45% notes, maturing September 15, 2017 and 2020, respectively, NiSource Finance settled $900 million of forward starting interest rate swap agreements with six counterparties. NiSource paid an aggregate settlement payment of $35.5 million which is being amortized from 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, 2011, accumulated other comprehensive loss includes $12.1 million related to forward starting interest rate swap settlement. These derivative contracts are accounted for as a cash flow hedge.

As of June 30, 2011, NiSource holds a 47.5% interest in Millennium. During 2008, Millennium entered into various interest rate swap agreements in order to protect against the risk of increasing interest rates. During August 2010, Millennium completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

private placement issuance of two tranches of notes totaling $725.0 million: $375.0 million at 5.33% due June 30, 2027, and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium repaid all outstanding borrowings under the credit agreement, terminated the sponsor guarantee and cash settled the interest rate hedges. These interest rate hedges were accounted for as cash flow hedges by Millennium. As it reports Millennium as an equity method investment, NiSource is required to recognize a proportional share of Millennium’s OCI. NiSource’s proportionate share of the remaining unrealized loss is $20.6 million, net of tax. Millennium is amortizing the unrealized loss related to these terminated interest rate swaps into earnings using the effective interest method through interest expense as interest payments are made. NiSource records its proportionate share of the amortization as Equity Earnings in Unconsolidated Affiliates at the Condensed Statements of Consolidated Income (unaudited).

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)		2011				2010
Balance Sheet Location		Fair Value				Fair Value
Derivatives designated as hedging instruments
Interest rate risk activities
Price risk management assets (current)		$	—			$	—
Price risk management assets (noncurrent)			60.7				61.1
Total derivatives designated as hedging instruments		$	60.7			$	61.1
Derivatives not designated as hedging instruments
Commodity price risk programs
Price risk management assets (current)		$	116.0			$	159.5
Price risk management assets (noncurrent)			129.9				179.2
Total derivatives not designated as hedging instruments		$	245.9			$	338.7
Total Asset Derivatives		$	306.6			$	399.8

		June 30,				December 31,
Liability Derivatives (in millions)		2011				2010
Balance Sheet Location		Fair Value				Fair Value
Derivatives designated as hedging instruments
Commodity price risk programs
Price risk management liabilities (current)		$	0.5			$	1.0
Price risk management liabilities (noncurrent)			0.1				0.2
Total derivatives designated as hedging instruments		$	0.6			$	1.2
Derivatives not designated as hedging instruments
Commodity price risk programs
Price risk management liabilities (current)		$	134.5			$	172.9
Price risk management liabilities (noncurrent)			127.7				181.4
Total derivatives not designated as hedging instruments		$	262.2			$	354.3
Total Liability Derivatives		$	262.8			$	355.5

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

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		June 30,				June 30,				into Income (Effective		June 30,				June 30,
Hedging Relationships		2011				2010				Portion)		2011				2010
Commodity price risk programs		$	—			$	0.4			Cost of Sales		$	0.2			$	0.3
Interest rate risk activities			0.4				0.4			Interest expense, net			(0.7	)			(0.7	)
Total		$	0.4			$	0.8					$	(0.5	)		$	(0.4	)

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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
		Portion)								Reclassified from AOCI		Portion)
Derivatives in Cash Flow		June 30,				June 30,				into Income (Effective		June 30,				June 30,
Hedging Relationships		2011				2010				Portion)		2011				2010
Commodity price risk programs		$	0.5			$	0.2			Cost of Sales		$	0.8			$	0.8
Interest rate risk activities			0.8				0.8			Interest expense, net			(1.3	)			(1.3	)
Total		$	1.3			$	1.0					$	(0.5	)		$	(0.5	)

Three Months Ended, (in millions):

				Amount of Gain (Loss) Recognized
		Location of Gain (Loss)		in Income on Derivative
		Recognized in Income on		(Ineffective Portion and Amount
		Derivative (Ineffective Portion		Excluded from Effectiveness
Derivatives in Cash Flow Hedging		and Amount Excluded from		Testing)
Relationships		Effectiveness Testing)		June 30, 2011				June 30, 2010
Commodity price risk programs		Cost of Sales		$	—			$	—
Interest rate risk activities		Interest expense, net			—				—
Total				$	—			$	—

Six Months Ended, (in millions)

				Amount of Gain (Loss) Recognized
		Location of Gain (Loss)		in Income on Derivative
		Recognized in Income on		(Ineffective Portion and Amount
		Derivative (Ineffective Portion		Excluded from Effectiveness
Derivatives in Cash Flow Hedging		and Amount Excluded from		Testing)
Relationships		Effectiveness Testing)		June 30, 2011				June 30, 2010
Commodity price risk programs		Cost of Sales		$	—			$	—
Interest rate risk activities		Interest expense, net			—				—
Total				$	—			$	—

It is anticipated that during the next twelve months the expiration and settlement of cash flow hedge contracts will result in income statement recognition of amounts currently classified in accumulated other comprehensive loss of approximately $0.4 million of loss, net of taxes.

Derivatives in Fair Value Hedging Relationships

Three Months Ended, (in millions)

				Amount of (Loss) Gain Recognized
Derivatives in Fair Value Hedging		Location of (Loss) Gain Recognized in		in Income on Derivatives
Relationships		Income on Derivatives		June 30, 2011				June 30, 2010
Interest rate risk activities		Interest expense, net		$	9.8			$	4.0
Total				$	9.8			$	4.0

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Six 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		June 30, 2011				June 30, 2010
Interest rate risk activities		Interest expense, net		$	(0.4	)		$	6.1
Total				$	(0.4	)		$	6.1

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		June 30, 2011				June 30, 2010
Fixed-rate debt		Interest expense, net		$	(9.8	)		$	(4.0	)
Total				$	(9.8	)		$	(4.0	)

Six 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		June 30, 2011				June 30, 2010
Fixed-rate debt		Interest expense, net		$	0.4			$	(6.1	)
Total				$	0.4			$	(6.1	)

Derivatives not designated as hedging instruments

Three Months Ended, (in millions)

				Amount of Realized/Unrealized Gain
		Location of Gain (Loss)		(Loss) Recognized in Income on
Derivatives Not Designated as Hedging		Recognized in		Derivatives *
Instruments		Income on Derivatives		June 30, 2011				June 30, 2010
Commodity price risk programs		Gas Distribution revenues		$	(0.1	)		$	4.2
Commodity price risk programs		Other revenues			7.8				(4.5	)
Commodity price risk programs		Cost of Sales			(4.5	)			(1.0	)
Total				$	3.2			$	(1.3	)

*

For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed in the table above, gains of $3.4 million and $4.4 million for the second quarter of 2011 and 2010, 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.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Six Months Ended, (in millions)

				Amount of Realized/Unrealized Gain
		Location of Gain (Loss)		(Loss) Recognized in Income on
Derivatives Not Designated as Hedging		Recognized in		Derivatives *
Instruments		Income on Derivatives		June 30, 2011				June 30, 2010
Commodity price risk programs		Gas Distribution revenues		$	(21.8	)		$	(16.8	)
Commodity price risk programs		Other revenues			18.4				72.7
Commodity price risk programs		Cost of Sales			(7.8	)			(72.2	)
Total				$	(11.2	)		$	(16.3	)

*

For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed in the table above, losses of $19.3 million and $16.2 million for the six months of 2011 and 2010, respectively, were deferred as allowed per regulatory orders. These amounts will be amortized to income over future periods of up to twelve months as specified in a regulatory order.

NiSource has not reclassified earnings from accumulated other comprehensive income to Cost of Sales due to the probability that certain forecasted transactions would not occur for the six months ended June 30, 2011 and 2010.

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

Certain NiSource affiliates have physical commodity purchase agreements that contain “ratings triggers” that require increases in collateral if the credit rating of NiSource or certain of its affiliates are rated below BBB- by Standard & Poor’s or below Baa3 by Moody’s. These agreements are primarily for the physical purchase or sale of natural gas and electricity. The collateral requirement from a downgrade below the ratings trigger levels would amount to approximately $2.0 million. In addition to agreements with ratings triggers, there are some agreements that contain “adequate assurance” or “material adverse change” provisions that could result in additional credit support such as letters of credit and cash collateral to transact business.

NiSource had $154.4 million and $198.3 million of cash on deposit with brokers for margin requirements associated with open derivative positions reflected within “Restricted cash” on the Condensed Consolidated Balance Sheets (unaudited) as of June 30, 2011 and December 31, 2010, respectively.

10. Fair Value Disclosures

A. Fair Value Measurements.

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

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

		Quoted Prices in				Significant
		Active Markets				Other				Significant
		for Identical				Observable				Unobservable
Recurring Fair Value Measurements		Assets				Inputs				Inputs				Balance as of
June 30, 2011 (in millions)		(Level 1)				(Level 2)				(Level 3)				June 30, 2011
Assets
Commodity Price risk management assets:
Physical price risk programs		$	—			$	122.3			$	—			$	122.3
Financial price risk programs			121.1				2.5				—				123.6
Interest rate risk activities			—				60.7				—				60.7
Available-for-sale securities			38.8				42.4				—				81.2
Total		$	159.9			$	227.9			$	—			$	387.8
Liabilities
Commodity Price risk management liabilities:
Physical price risk programs		$	—			$	2.8			$	—			$	2.8
Financial price risk programs			257.1				2.1				0.8				260.0
Total		$	257.1			$	4.9			$	0.8			$	262.8

		Quoted Prices in				Significant
		Active Markets				Other				Significant
		for Identical				Observable				Unobservable
Recurring Fair Value Measurements		Assets				Inputs				Inputs				Balance as of
December 31, 2010 (in millions)		(Level 1)				(Level 2)				(Level 3)				December 31, 2010
Assets
Commodity Price risk management assets:
Physical price risk programs		$	—			$	161.4			$	—			$	161.4
Financial price risk programs			173.8				3.2				0.3				177.3
Interest rate risk activities			—				61.1				—				61.1
Available-for-sale securities			43.5				37.9				—				81.4
Total		$	217.3			$	263.6			$	0.3			$	481.2
Liabilities
Commodity Price risk management liabilities:
Physical price risk programs		$	—			$	3.6			$	—			$	3.6
Financial price risk programs			348.5				3.3				0.1				351.9
Total		$	348.5			$	6.9			$	0.1			$	355.5

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.

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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

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

		Amortized				Total				Total				Fair
(in millions)		Cost				Gains				Losses				Value
Available-for-sale debt securities, June 30, 2011
U.S. Treasury		$	38.4			$	0.6			$	(0.2	)		$	38.8
Corporate/Other			41.2				1.3				(0.1	)			42.4
Total Available-for-sale debt securities		$	79.6			$	1.9			$	(0.3	)		$	81.2

		Amortized				Total				Total				Fair
(in millions)		Cost				Gains				Losses				Value
Available-for-sale debt securities, Dec. 31, 2010
U.S. Treasury		$	43.4			$	0.6			$	(0.5	)		$	43.5
Corporate/Other			36.1				2.0				(0.2	)			37.9
Total Available-for-sale debt securities		$	79.5			$	2.6			$	(0.7	)		$	81.4