Edgar Filing: INTEGRYS ENERGY GROUP, INC.

TEG-9.30.2013-10Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2013

[ ] 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	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-11337	INTEGRYS ENERGY GROUP, INC. (A Wisconsin Corporation) 130 East Randolph Street Chicago, IL 60601-6207 (312) 228-5400	39-1775292

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 [X] No [ ]

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

Yes [X] No [ ]

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

Large accelerated filer [X] Accelerated filer [ ]

Non-accelerated filer [ ] Smaller reporting company [ ]

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

Yes [ ] No [X]

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common stock, $1 par value,

79,807,435 shares outstanding at

November 4, 2013

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INTEGRYS ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2013

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				Page
	Forward-Looking Statements			1
PART I.	FINANCIAL INFORMATION			2
Item 1.	Financial Statements (Unaudited)			2
	Condensed Consolidated Statements of Income			2
	Condensed Consolidated Statements of Comprehensive Income			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Condensed Notes to Financial Statements			6
			Page
	Note 1	Financial Information	6
	Note 2	Cash and Cash Equivalents	6
	Note 3	Risk Management Activities	7
	Note 4	Acquisitions	10
	Note 5	Discontinued Operations	12
	Note 6	Investment in ATC	13
	Note 7	Inventories	14
	Note 8	Goodwill and Other Intangible Assets	14
	Note 9	Short-Term Debt and Lines of Credit	16
	Note 10	Long-Term Debt	16
	Note 11	Income Taxes	17
	Note 12	Commitments and Contingencies	18
	Note 13	Guarantees	20
	Note 14	Employee Benefit Plans	21
	Note 15	Stock-Based Compensation	21
	Note 16	Common Equity	24
	Note 17	Accumulated Other Comprehensive Loss	26
	Note 18	Variable Interest Entities	27
	Note 19	Fair Value	28
	Note 20	Advertising Costs	33
	Note 21	Regulatory Environment	33
	Note 22	Segments of Business	36
	Note 23	New Accounting Pronouncements	38
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			40
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			58
ITEM 4.	Controls and Procedures			59
PART II.	OTHER INFORMATION			60
ITEM 1.	Legal Proceedings			60
ITEM 1A.	Risk Factors			60
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			60
ITEM 6.	Exhibits			60
Signature				61
EXHIBIT INDEX				62

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Acronyms Used in this Quarterly Report on Form 10-Q



AFUDC	Allowance for Funds Used During Construction
AMRP	Accelerated Natural Gas Main Replacement Program
ATC	American Transmission Company LLC
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	United States Generally Accepted Accounting Principles
IBS	Integrys Business Support, LLC
ICC	Illinois Commerce Commission
IRS	United States Internal Revenue Service
ITF	Integrys Transportation Fuels, LLC (doing business as Trillium CNG)
LIFO	Last-in, First-out
MERC	Minnesota Energy Resources Corporation
MGU	Michigan Gas Utilities Corporation
MISO	Midcontinent Independent System Operator, Inc.
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
N/A	Not Applicable
NSG	North Shore Gas Company
OCI	Other Comprehensive Income
PELLC	Peoples Energy, LLC (formerly known as Peoples Energy Corporation)
PGL	The Peoples Gas Light and Coke Company
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
UPPCO	Upper Peninsula Power Company
WDNR	Wisconsin Department of Natural Resources
WPS	Wisconsin Public Service Corporation

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Forward-Looking Statements

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are not guarantees of future results and conditions. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.

Forward-looking statements involve a number of risks and uncertainties. Some risks that could cause actual results to differ materially from those expressed or implied in forward-looking statements include those described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2012, as may be amended or supplemented in Part II, Item 1A of our subsequently filed Quarterly Reports on Form 10-Q (including this report), and those identified below:


•	The timing and resolution of rate cases and related negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated businesses;


•	Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards;


•	Other federal and state legislative and regulatory changes, including deregulation and restructuring of the electric and natural gas utility industries, financial reform, health care reform, energy efficiency mandates, reliability standards, pipeline integrity and safety standards, and changes in tax and other laws and regulations to which we and our subsidiaries are subject;


•	Costs and effects of litigation and administrative proceedings, settlements, investigations, and claims;


•	Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our and our subsidiaries’ liquidity and financing efforts;


•	The risks associated with changing commodity prices, particularly natural gas and electricity, and the available sources of fuel, natural gas, and purchased power, including their impact on margins, working capital, and liquidity requirements;


•	The timing and outcome of any audits, disputes, and other proceedings related to taxes;


•	The effects, extent, and timing of additional competition or regulation in the markets in which our subsidiaries operate;


•	The ability to retain market-based rate authority;


•	The risk associated with the value of goodwill or other intangible assets and their possible impairment;


•	The investment performance of employee benefit plan assets and related actuarial assumptions, which impact future funding requirements;


•	The impact of unplanned facility outages;


•	Changes in technology, particularly with respect to new, developing, or alternative sources of generation;


•	The effects of political developments, as well as changes in economic conditions and the related impact on customer use, customer growth, and our ability to adequately forecast energy use for our customers;


•	Potential business strategies, including mergers, acquisitions, and construction or disposition of assets or businesses, which cannot be assured to be completed timely or within budgets;


•	The risk of terrorism or cyber security attacks, including the associated costs to protect our assets and respond to such events;


•	The risk of failure to maintain the security of personally identifiable information, including the associated costs to notify affected persons and to mitigate their information security concerns;


•	The effectiveness of risk management strategies, the use of financial and derivative instruments, and the related recovery of these costs from customers in rates;


•	The risk of financial loss, including increases in bad debt expense, associated with the inability of our and our subsidiaries’ counterparties, affiliates, and customers to meet their obligations;


•	Unusual weather and other natural phenomena, including related economic, operational, and/or other ancillary effects of any such events;


•	The ability to use tax credit and loss carryforwards;


•	The financial performance of ATC and its corresponding contribution to our earnings;


•	The effect of accounting pronouncements issued periodically by standard-setting bodies; and


•	Other factors discussed elsewhere herein and in other reports we file with the SEC.

Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

INTEGRYS ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	Three Months Ended						Nine Months Ended
	September 30						September 30
(Millions, except per share data)	2013			2012			2013			2012
Utility revenues	$	606.9		$	582.3		$	2,425.1		$	2,116.9
Nonregulated revenues	522.8			345.4			1,498.8			898.3
Total revenues	1,129.7			927.7			3,923.9			3,015.2

Utility cost of fuel, natural gas, and purchased power	222.8			228.2			1,083.9			926.4
Nonregulated cost of sales	475.3			264.0			1,360.0			730.0
Operating and maintenance expense	282.3			240.3			866.1			748.6
Depreciation and amortization expense	69.6			62.9			196.0			187.6
Taxes other than income taxes	24.4			23.8			76.4			73.9
Operating income	55.3			108.5			341.5			348.7

Earnings from equity method investments	23.1			22.2			68.2			65.5
Miscellaneous income	12.1			3.1			23.3			7.2
Interest expense	33.1			29.9			91.0			90.0
Other income (expense)	2.1			(4.6		)	0.5			(17.3		)

Income before taxes	57.4			103.9			342.0			331.4
Provision for income taxes	18.0			29.6			124.3			106.6
Net income from continuing operations	39.4			74.3			217.7			224.8

Discontinued operations, net of tax	(0.6		)	(8.0		)	4.7			(9.2		)
Net income	38.8			66.3			222.4			215.6

Preferred stock dividends of subsidiary	(0.7		)	(0.7		)	(2.3		)	(2.3		)
Noncontrolling interest in subsidiaries	—			0.1			0.1			0.1
Net income attributed to common shareholders	$	38.1		$	65.7		$	220.2		$	213.4

Average shares of common stock
Basic	79.8			78.5			79.3			78.5
Diluted	80.2			79.3			79.9			79.3

Earnings per common share (basic)
Net income from continuing operations	$	0.49		$	0.94		$	2.72		$	2.84
Discontinued operations, net of tax	(0.01		)	(0.10		)	0.06			(0.12		)
Earnings per common share (basic)	$	0.48		$	0.84		$	2.78		$	2.72

Earnings per common share (diluted)
Net income from continuing operations	$	0.48		$	0.93		$	2.70		$	2.81
Discontinued operations, net of tax	(0.01		)	(0.10		)	0.06			(0.12		)
Earnings per common share (diluted)	$	0.47		$	0.83		$	2.76		$	2.69

Dividends per common share declared	$	0.68		$	0.68		$	2.04		$	2.04

The accompanying condensed notes are an integral part of these statements.

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INTEGRYS ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended						Nine Months Ended
	September 30						September 30
(Millions)	2013			2012			2013			2012
Net income	$	38.8		$	66.3		$	222.4		$	215.6

Other comprehensive income, net of tax:
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of $ – million, $0.1 million, $ – million, and $(0.1) million, respectively	—			0.1			0.7			(0.1		)
Reclassification of net losses to net income, net of tax of $0.2 million, $1.0 million, $1.7 million, and $2.6 million, respectively	0.3			1.6			2.7			4.1
Cash flow hedges, net	0.3			1.7			3.4			4.0

Defined benefit plans
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.4 million, $0.2 million, $1.2 million, and $0.7 million, respectively	0.6			0.4			1.8			1.1
Other comprehensive income, net of tax	0.9			2.1			5.2			5.1
Comprehensive income	39.7			68.4			227.6			220.7
Preferred stock dividends of subsidiary	(0.7		)	(0.7		)	(2.3		)	(2.3		)
Noncontrolling interest in subsidiaries	—			0.1			0.1			0.1
Comprehensive income attributed to common shareholders	$	39.0		$	67.8		$	225.4		$	218.5

The accompanying condensed notes are an integral part of these statements.

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INTEGRYS ENERGY GROUP, INC.



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	September 30			December 31
(Millions)	2013			2012
Assets
Cash and cash equivalents	$	26.1		$	27.4
Collateral on deposit	61.1			41.0
Accounts receivable and accrued unbilled revenues, net of reserves of $45.3 and $43.5, respectively	625.3			796.8
Inventories	341.7			271.9
Assets from risk management activities	154.9			145.4
Regulatory assets	101.7			110.8
Assets held for sale	0.7			10.1
Deferred income taxes	38.4			64.3
Prepaid taxes	141.8			152.8
Other current assets	30.0			38.6
Current assets	1,521.7			1,659.1

Property, plant, and equipment, net of accumulated depreciation of $3,307.9 and $3,114.7, respectively	6,198.8			5,501.9
Regulatory assets	1,784.6			1,813.8
Assets from risk management activities	58.1			45.3
Equity method investments	534.5			512.2
Goodwill	662.1			658.3
Other long-term assets	161.5			136.8
Total assets	$	10,921.3		$	10,327.4

Liabilities and Equity
Short-term debt	$	388.0		$	482.4
Current portion of long-term debt	276.5			313.5
Accounts payable	475.4			457.7
Liabilities from risk management activities	157.5			181.9
Accrued taxes	41.2			83.0
Regulatory liabilities	56.1			65.6
Liabilities held for sale	—			0.2
Other current liabilities	237.9			229.0
Current liabilities	1,632.6			1,813.3

Long-term debt	2,506.2			1,931.7
Deferred income taxes	1,320.4			1,203.8
Deferred investment tax credits	48.4			49.3
Regulatory liabilities	390.4			370.5
Environmental remediation liabilities	613.6			651.5
Pension and other postretirement benefit obligations	573.0			625.2
Liabilities from risk management activities	59.6			58.4
Asset retirement obligations	426.8			411.2
Other long-term liabilities	138.8			135.7
Long-term liabilities	6,077.2			5,437.3

Commitments and contingencies

Common stock – $1 par value; 200,000,000 shares authorized; 79,757,715 shares issued; 79,289,748 shares outstanding	79.8			78.3
Additional paid-in capital	2,648.1			2,574.6
Retained earnings	489.8			431.5
Accumulated other comprehensive loss	(35.7		)	(40.9		)
Shares in deferred compensation trust	(22.7		)	(17.7		)
Total common shareholders’ equity	3,159.3			3,025.8

Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1			51.1
Noncontrolling interest in subsidiaries	1.1			(0.1		)
Total liabilities and equity	$	10,921.3		$	10,327.4

The accompanying condensed notes are an integral part of these statements.

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INTEGRYS ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(Millions)	2013			2012
Operating Activities
Net income	$	222.4		$	215.6
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax	(4.7		)	9.2
Depreciation and amortization expense	196.0			187.6
Recoveries and refunds of regulatory assets and liabilities	35.2			12.6
Net unrealized gains on energy contracts	(18.8		)	(42.8		)
Bad debt expense	22.2			19.3
Pension and other postretirement expense	47.4			46.7
Pension and other postretirement contributions	(65.0		)	(247.8		)
Deferred income taxes and investment tax credits	123.4			86.3
Equity income, net of dividends	(14.1		)	(13.4		)
Termination of tolling agreement with Fox Energy Company LLC	(50.0		)	—
Other	33.4			32.8
Changes in working capital
Collateral on deposit	(20.1		)	(1.1		)
Accounts receivable and accrued unbilled revenues	80.4			232.6
Inventories	(70.1		)	(20.9		)
Other current assets	(7.6		)	66.8
Accounts payable	21.9			(45.0		)
Other current liabilities	(21.0		)	5.8
Net cash provided by operating activities	510.9			544.3

Investing Activities
Capital expenditures	(474.7		)	(437.8		)
Proceeds from the sale or disposal of assets	4.6			8.2
Capital contributions to equity method investments	(10.2		)	(24.0		)
Acquisition of Fox Energy Company LLC	(391.6		)	—
Acquisitions at Integrys Energy Services	(12.4		)	—
Grant received related to Crane Creek Wind Project	69.0			—
Other	(6.1		)	4.8
Net cash used for investing activities	(821.4		)	(448.8		)

Financing Activities
Short-term debt, net	(294.4		)	107.0
Borrowing on term credit facility	200.0			—
Issuance of long-term debt	724.0			28.0
Repayment of long-term debt	(187.0		)	(28.2		)
Proceeds from stock option exercises	38.5			54.9
Shares purchased for stock-based compensation	(2.0		)	(85.1		)
Payment of dividends
Preferred stock of subsidiary	(2.3		)	(2.3		)
Common stock	(151.6		)	(159.0		)
Payments made on derivative contracts related to divestitures classified as financing activities	(5.7		)	(27.9		)
Other	(13.2		)	0.5
Net cash provided by (used for) financing activities	306.3			(112.1		)

Change in cash and cash equivalents – continuing operations	(4.2		)	(16.6		)
Change in cash and cash equivalents – discontinued operations
Net cash provided by operating activities	1.3			6.7
Net cash provided by (used for) investing activities	1.6			(0.1		)
Net change in cash and cash equivalents	(1.3		)	(10.0		)
Cash and cash equivalents at beginning of period	27.4			28.1
Cash and cash equivalents at end of period	$	26.1		$	18.1

The accompanying condensed notes are an integral part of these statements.

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INTEGRYS ENERGY GROUP, INC. AND SUBSIDIARIES

CONDENSED NOTES TO FINANCIAL STATEMENTS (Unaudited)

September 30, 2013

NOTE 1 — FINANCIAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated statements of comprehensive income, condensed consolidated balance sheets, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to "us," "we," "our," or "ours," we are referring to Integrys Energy Group, Inc.

We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2012. Financial results for an interim period may not give a true indication of results for the year.

In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation.

NOTE 2 — CASH AND CASH EQUIVALENTS

Short-term investments with an original maturity of three months or less are reported as cash equivalents.

The following is a supplemental disclosure to our statements of cash flows:



	Nine Months Ended September 30
(Millions)	2013			2012
Cash paid for interest	$	60.7		$	60.0
Cash received for income taxes	(2.6		)	(45.7		)

Cash received for income taxes decreased $43.1 million, primarily driven by a federal income tax refund received in 2012 for a net operating loss incurred in 2010 that was carried back to a prior year. The 2010 net operating loss was driven by bonus depreciation.

Significant noncash transactions were:



	Nine Months Ended September 30
(Millions)	2013		2012
Construction costs funded through accounts payable	$	98.4	$	78.8
Equity issued for stock-based compensation plans	26.5		—
Equity issued for reinvested dividends	9.1		—
Contingent consideration and payables related to the acquisition of Compass Energy Services *	7.9		—


*	See Note 4, "Acquisitions," for more information on the contingent consideration.

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NOTE 3 — RISK MANAGEMENT ACTIVITIES

The following tables show our assets and liabilities from risk management activities:



		September 30, 2013
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	2.2	$	5.4
Natural gas contracts	Long-term	0.5		0.6
Financial transmission rights (FTRs)	Current	3.4		0.4
Petroleum product contracts	Current	—		0.2
Coal contracts	Current	—		2.6
Coal contracts	Long-term	1.5		0.1

Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	48.9		37.6
Natural gas contracts	Long-term	24.6		14.6
Electric contracts	Current	100.4		111.3
Electric contracts	Long-term	31.5		44.3
	Current	154.9		157.5
	Long-term	58.1		59.6
Total		$	213.0	$	217.1

* We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.



		December 31, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	2.5	$	14.0
Natural gas contracts	Long-term	0.9		0.8
FTRs	Current	2.1		0.1
Petroleum product contracts	Current	0.2		—
Coal contracts	Current	0.3		4.7
Coal contracts	Long-term	2.2		4.3
Cash flow hedges
Natural gas contracts	Current	—		0.4

Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	51.7		48.5
Natural gas contracts	Long-term	11.5		7.6
Electric contracts	Current	88.6		114.2
Electric contracts	Long-term	30.7		45.7
	Current	145.4		181.9
	Long-term	45.3		58.4
Total		$	190.7	$	240.3

* We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

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The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:



	September 30, 2013
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility segments	$	5.9	$	2.3	$	3.6
Nonregulated segments	205.4		119.2		86.2
Total	211.3		121.5		89.8
Derivative assets not subject to master netting or similar arrangements	1.7				1.7
Total risk management assets	$	213.0			$	91.5

Derivative liabilities subject to master netting or similar arrangements
Utility segments	$	6.6	$	2.7	$	3.9
Nonregulated segments	207.1		145.2		61.9
Total	213.7		147.9		65.8
Derivative liabilities not subject to master netting or similar arrangements	3.4				3.4
Total risk management liabilities	$	217.1			$	69.2



	December 31, 2012
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility segments	$	5.7	$	3.0	$	2.7
Nonregulated segments	182.5		145.4		37.1
Total	188.2		148.4		39.8
Derivative assets not subject to master netting or similar arrangements	2.5				2.5
Total risk management assets	$	190.7			$	42.3

Derivative liabilities subject to master netting or similar arrangements
Utility segments	$	15.3	$	3.8	$	11.5
Nonregulated segments	215.4		159.8		55.6
Total	230.7		163.6		67.1
Derivative liabilities not subject to master netting or similar arrangements	9.6				9.6
Total risk management liabilities	$	240.3			$	76.7

Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above table. These amounts may offset (or conditionally offset) the net amounts presented in the above table.

Financial collateral received or provided is restricted to the extent that it is required per the terms of the related agreements. The following table shows our cash collateral positions:



(Millions)	September 30, 2013		December 31, 2012
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements	$	60.0	$	39.9
Other	1.1		1.1
Cash collateral received from others related to contracts under master netting or similar arrangements *	—		0.2

* Reflected in other current liabilities on the balance sheets.

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Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The following table shows the aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position:



(Millions)	September 30, 2013		December 31, 2012
Integrys Energy Services	$	83.3	$	108.9
Utility segments	5.2		14.0

If all of the credit risk-related contingent features contained in commodity instruments (including derivatives, nonderivatives, normal purchase and normal sales contracts, and applicable payables and receivables) had been triggered, our collateral requirement would have been as follows:



(Millions)	September 30, 2013		December 31, 2012
Collateral that would have been required:
Integrys Energy Services	$	185.4	$	173.8
Utility segments	2.2		10.1
Collateral already satisfied:
Integrys Energy Services — Letters of credit	4.5		3.2
Collateral remaining:
Integrys Energy Services	180.9		170.6
Utility segments	2.2		10.1

Utility Segments

Non-Hedge Derivatives

Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts (futures, options, and swaps), and FTRs used to manage electric transmission congestion costs. Both the electric and natural gas utility segments use futures, options, and swaps to manage the risks associated with the market price volatility of natural gas supply costs, and the costs of gasoline and diesel fuel used by utility vehicles. The electric utility segment also uses oil futures and options to manage price risk related to coal transportation.

The utilities had the following notional volumes of outstanding derivative contracts:

September 30, 2013

December 31, 2012

Purchases

Sales

Other Transactions

Purchases

Sales

Other Transactions

Natural gas (millions of therms)

1,104.1

1.7

N/A

1,072.6

0.1

N/A

FTRs (millions of kilowatt-hours)

N/A

5,858.1

N/A

4,057.2

Petroleum products (barrels)

76,822.0

9,000.0

N/A

62,811.0

—

N/A

Coal (millions of tons)

5.1

N/A

5.1

N/A

The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities:



		Three Months Ended September 30						Nine Months Ended September 30
(Millions)	Financial Statement Presentation	2013			2012			2013			2012
Natural gas	Balance Sheet — Regulatory assets (current)	$	(0.5	)	$	10.2		$	6.9		$	22.9
Natural gas	Balance Sheet — Regulatory assets (long-term)	1.8			3.8			1.6			7.7
Natural gas	Balance Sheet — Regulatory liabilities (current)	(0.4		)	(3.4		)	(0.2		)	(2.9		)
Natural gas	Balance Sheet — Regulatory liabilities (long-term)	—			0.8			(0.3		)	1.3
Natural gas	Income Statement — Utility cost of fuel, natural gas, and purchased power	—			0.1			—			0.2
Natural gas	Income Statement — Operating and maintenance expense	(0.1		)	0.1			(0.2		)	0.1
FTRs	Balance Sheet — Regulatory assets (current)	0.8			—			—			(0.4		)
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.2		)	(0.2		)	(0.3		)	0.5
Petroleum	Balance Sheet — Regulatory assets (current)	0.1			0.2			—			0.1
Petroleum	Balance Sheet — Regulatory liabilities (current)	—			0.1			—			0.1
Petroleum	Income Statement — Operating and maintenance expense	(0.2		)	0.1			(0.2		)	0.1
Coal	Balance Sheet — Regulatory assets (current)	(0.6		)	0.7			2.1			(2.5		)
Coal	Balance Sheet — Regulatory assets (long-term)	0.2			(0.1		)	4.2			0.1
Coal	Balance Sheet — Regulatory liabilities (current)	—			—			(0.3		)	—
Coal	Balance Sheet — Regulatory liabilities (long-term)	1.5			—			(0.7		)	—

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Nonregulated Segments

Nonhedge Derivatives

Integrys Energy Services enters into derivative contracts such as futures, forwards, options, and swaps that are used to manage commodity price risk primarily associated with retail electric and natural gas customer contracts.

Integrys Energy Services had the following notional volumes of outstanding derivative contracts:



	September 30, 2013		December 31, 2012
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	1,108.5	1,011.8	782.0	679.0
Electric (kilowatt-hours)	50,956.9	32,059.6	54,127.6	31,809.6
Foreign exchange contracts (Canadian dollars)	—	—	0.4	0.4

Gains (losses) related to derivative contracts are recognized currently in earnings, as shown in the table below:



		Three Months Ended September 30						Nine Months Ended September 30
(Millions)	Income Statement Presentation	2013			2012			2013			2012
Natural gas	Nonregulated revenue	$	(21.1	)	$	(4.4	)	$	16.1		$	7.0
Natural gas	Nonregulated cost of sales	25.0			—			(9.5		)	—
Natural gas	Nonregulated revenue (reclassified from accumulated OCI) *	—			(0.1		)	(0.2		)	(1.6		)
Electric	Nonregulated revenue	36.0			49.1			22.4			(10.5		)
Electric	Nonregulated cost of sales	(6.6		)	—			2.1			—
Electric	Nonregulated revenue (reclassified from accumulated OCI) *	(0.2		)	(1.9		)	(3.2		)	(3.3		)
Total		$	33.1		$	42.7		$	27.7		$	(8.4	)


*	Represents amounts reclassified from accumulated OCI related to cash flow hedges that were dedesignated in prior periods.

In the next 12 months, insignificant losses related to discontinued cash flow hedges of natural gas and electric contracts are expected to be recognized in earnings as the forecasted transactions occur. These amounts are expected to be offset by the settlement of the related nonderivative customer contracts.

NOTE 4 — ACQUISITIONS

Agreement to Purchase Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota

In September 2013, MERC entered into an agreement to purchase Alliant Energy Corporation's natural gas distribution business in southeast Minnesota. This transaction is subject to state and federal regulatory approvals. The purchase price will be based on book value as of the closing date, and will be around $11 million. This acquisition will not be material to us.

Acquisition of Compass Energy Services

In May 2013, Integrys Energy Services acquired all of the equity interests of Compass Energy Services, Inc. and its wholly-owned subsidiary (Compass), a nonregulated retail natural gas business supplying commercial and industrial customers primarily in the Mid Atlantic and Ohio regions. This transaction expands Integrys Energy Services' retail natural gas presence and provides a solid foundation for future growth in these regions.

This acquisition was not material to us. Integrys Energy Services paid $12.4 million to acquire this business. Under the terms of the purchase agreement, the former owners of Compass will be eligible to receive additional cash consideration of up to $8.0 million (but no less than $3.0 million), based upon the financial performance of Compass over the next five years. Integrys Energy Services recorded liabilities of $7.7 million related to this contingent consideration.

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The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:



(Millions)
Assets acquired
Inventories	$	0.7
Assets from risk management activities (current)	15.1
Other current assets	1.1
Assets from risk management activities (long-term)	9.3
Other long-term assets	6.1
Total assets acquired	$	32.3

Liabilities assumed
Liabilities from risk management activities (current)	$	8.3
Other current liabilities	0.5
Liabilities from risk management activities (long-term)	3.4
Total liabilities assumed	$	12.2

Acquisition of Fox Energy Center

In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.

The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but expected to run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:



(Millions)
Assets acquired⁽¹⁾
Inventories	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets ⁽²⁾	15.6
Total assets acquired	$	393.4

Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8


⁽¹⁾	Relates to the electric utility segment.


⁽²⁾	Intangible assets recorded for contractual services agreements. See Note 8, "Goodwill and Other Intangible Assets," for more information.

Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW. In the current rate case, WPS proposed amortizing the regulatory asset over a nine-year period, beginning January 1, 2014. This has not been challenged, and WPS expects PSCW approval in the final decision in this rate case.

The purchase was financed with a combination of short-term debt and cash provided by operations. WPS intends to replace the short-term debt in the fourth quarter of 2013 with long-term financing.

WPS received regulatory approval to defer incremental costs associated with the purchase of the facility. Operating costs for the Fox Energy Center subsequent to the date of acquisition are included in our income statement. Due to regulatory deferral, these costs had no impact on net income. Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS's regulated fleet, used to serve its customers.

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NOTE 5 — DISCONTINUED OPERATIONS

Discontinued Operations at Holding Company and Other Segment

During the nine months ended September 30, 2013, and 2012, we recorded $5.9 million and $1.8 million of after-tax gains, respectively, in discontinued operations at the holding company and other segment. In 2013, we remeasured uncertain tax positions included in our liability for unrecognized tax benefits after effectively settling certain state income tax examinations. We reduced the provision for income taxes related to these remeasurements.

Discontinued Operations at Integrys Energy Services Segment

Potential Sale of Combined Locks Energy Center

Integrys Energy Services is currently pursuing the sale of the Combined Locks Energy Center (Combined Locks), a natural gas-fired co-generation facility located in Wisconsin, as part of its long-term energy asset strategy. An agreement to sell Combined Locks is expected to be entered into by the end of 2013.

The carrying values of the major classes of assets related to Combined Locks classified as held for sale on the balance sheets were as follows:



(Millions)	September 30, 2013		December 31, 2012
Inventories	$	0.5	$	0.5
Property, plant, and equipment, net of accumulated depreciation of $ – and $0.5 million, respectively	0.2		2.0
Total assets	$	0.7	$	2.5

A summary of the components of discontinued operations related to Combined Locks recorded on the income statements follows:



	Three Months Ended September 30						Nine Months Ended September 30
(Millions)	2013			2012			2013			2012
Nonregulated revenues	$	(0.1	)	$	—		$	(0.1	)	$	0.3
Nonregulated cost of sales	(0.1		)	(0.1		)	(0.2		)	(0.5		)
Operating and maintenance expense	(0.8		)	(0.1		)	(2.0		)	(0.3		)
Depreciation and amortization expense	—			(0.1		)	—			(0.2		)
Taxes other than income taxes	—			—			—			(0.1		)
Loss before taxes	(1.0		)	(0.3		)	(2.3		)	(0.8		)
Benefit for income taxes	0.4			0.2			0.9			0.3
Discontinued operations, net of tax	$	(0.6	)	$	(0.1	)	$	(1.4	)	$	(0.5	)

Sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

In March 2013, WPS Empire State, Inc, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse), both of which own natural gas-fired generation plants located in the state of New York. The cash proceeds from the sale were $1.6 million. The sale agreement also included a potential annual payment to Integrys Energy Services for a four-year period following the sale based on a certain level of earnings achieved by the buyer (an earn-out). Integrys Energy Services recorded a pre-tax impairment loss in operating and maintenance expense of $4.0 million ($2.4 million after tax) related to Beaver Falls and Syracuse during the third quarter of 2012 when the assets and liabilities were classified as held for sale.

The carrying values of the major classes of assets and liabilities related to Beaver Falls and Syracuse classified as held for sale on the balance sheet were as follows:



(Millions)	As of December 31, 2012
Inventories	$	1.8
Property, plant, and equipment	5.7
Other long-term assets	0.1
Total assets	$	7.6

Total liabilities – other current liabilities	$	0.2

In conjunction with the sale, the buyer assumed certain derivative contracts from WPS Empire State, Inc. Integrys Energy Services maintained these contracts to secure physical capacity for both its retail electric business obligations, as well as sales to external counterparties. The carrying value of the derivative contract liabilities assumed by the buyer was $6.8 million at closing. As of September 30, 2013, Integrys Energy Services is in the process of novating the external capacity contracts to the buyer.

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A summary of the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements were as follows:



	Three Months Ended			Nine Months Ended September 30
(Millions)	September 30, 2012			2013				2012
Nonregulated revenues	$	1.2		$	1.2			$	1.5
Nonregulated cost of sales	(0.7		)	(0.9		)		(1.6		)
Operating and maintenance expense	(4.6		)	0.4			*	(5.7		)
Depreciation and amortization expense	(0.2		)	—				(0.6		)
Taxes other than income taxes	—			(0.3		)		(1.1		)
Income (loss) before taxes	(4.3		)	0.4				(7.5		)
(Provision) benefit for income taxes	1.7			(0.2		)		3.0
Discontinued operations, net of tax	$	(2.6	)	$	0.2			$	(4.5	)


*	Includes a $1.0 million gain on sale at closing.

The sale of Beaver Falls and Syracuse may generate immaterial cash flows from a four-year annual earn-out payment. Integrys Energy Services will also continue to purchase capacity from these facilities to satisfy certain capacity obligations, but is in the process of novating a majority of these obligations to the buyer, and will continue to settle certain forward financial natural gas swaps under contracts that existed at the time of sale. Both of these transactions will generate cash flows, of which the majority will expire upon novation or within two years of the sale, and are not considered significant to the overall operations of Beaver Falls and Syracuse. Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Beaver Falls and Syracuse and also does not have significant continuing involvement in the operations of Beaver Falls and Syracuse. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Beaver Falls and Syracuse.

Sale of WPS Westwood Generation, LLC

In November 2012, Sunbury Holdings, LLC, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Westwood Generation, LLC (Westwood), a waste coal generation plant located in Pennsylvania. The cash proceeds related to the sale were $2.6 million. Integrys Energy Services also received a $4.0 million note receivable from the buyer with a seven and one-half year term. Integrys Energy Services recorded a pre-tax impairment loss in operating and maintenance expense of $8.4 million ($5.0 million after tax) related to Westwood during the third quarter of 2012 when the assets and liabilities were classified as held for sale.

A summary of the components of discontinued operations related to Westwood recorded on the income statements were as follows:



(Millions)	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Nonregulated revenues	$	2.2		$	8.2
Nonregulated cost of sales	(1.2		)	(3.6		)
Operating and maintenance expense	(9.3		)	(12.9		)
Depreciation and amortization expense	(0.3		)	(1.0		)
Taxes other than income taxes	(0.1		)	(0.2		)
Interest expense	(0.1		)	(0.4		)
Loss before taxes	(8.8		)	(9.9		)
Benefit for income taxes	3.5			3.9
Discontinued operations, net of tax	$	(5.3	)	$	(6.0	)

Integrys Energy Services will receive interest income for seven and one-half years from the sale date related to the note receivable from the buyer. Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Westwood and also does not have significant continuing involvement in the operations of Westwood. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Westwood.

NOTE 6 — INVESTMENT IN ATC

Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at September 30, 2013. ATC is a for-profit, transmission-only company regulated by FERC.

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The following table shows changes to our investment in ATC.



	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2013		2012		2013		2012
Balance at the beginning of period	$	492.2	$	456.4	$	476.6	$	439.4
Add: Earnings from equity method investment	22.3		21.7		66.0		63.8
Add: Capital contributions	3.4		8.5		10.2		17.0
Less: Dividends received	17.8		17.3		52.7		50.9
Balance at the end of period	$	500.1	$	469.3	$	500.1	$	469.3

Financial data for all of ATC is included in the following tables:



	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2013		2012		2013		2012
Income statement data
Revenues	$	160.4	$	150.3	$	464.3	$	450.1
Operating expenses	77.5		68.8		217.2		210.1
Other expense	20.2		21.0		62.6		62.1
Net income	$	62.7	$	60.5	$	184.5	$	177.9



(Millions)	September 30, 2013		December 31, 2012
Balance sheet data
Current assets	$	77.8	$	63.1
Noncurrent assets	3,455.4		3,274.7
Total assets	$	3,533.2	$	3,337.8

Current liabilities	$	353.6	$	251.5
Long-term debt	1,550.0		1,550.0
Other noncurrent liabilities	119.9		95.8
Shareholders’ equity	1,509.7		1,440.5
Total liabilities and shareholders’ equity	$	3,533.2	$	3,337.8

NOTE 7 — INVENTORIES

PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2013, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

NOTE 8 — GOODWILL AND OTHER INTANGIBLE ASSETS

The following table shows changes to our goodwill balances by segment during the nine months ended September 30, 2013:



(Millions)	Natural Gas Utility			Integrys Energy Services		Holding Company and Other		Total
Balance as of January 1, 2013
Gross goodwill	$	933.5		$	6.6	$	15.8	$	955.9
Accumulated impairment losses	(297.6		)	—		—		(297.6		)
Net goodwill	635.9			6.6		15.8		658.3
Adjustment to ITF patents/intellectual property *	—			—		3.8		3.8

Balance as of September 30, 2013
Gross goodwill	933.5			6.6		19.6		959.7
Accumulated impairment losses	(297.6		)	—		—		(297.6		)
Net goodwill	$	635.9		$	6.6	$	19.6	$	662.1


*	An immaterial adjustment was made to the gross goodwill balance at ITF in the second quarter of 2013 due to a correction to the life of certain intangible assets.

In the second quarter of 2013, annual impairment tests were completed at all of our reporting units that carried a goodwill balance. No impairments resulted from these tests.

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The identifiable intangible assets other than goodwill listed below are part of other current and long-term assets on the balance sheets. An insignificant amount was recorded as assets held for sale on the balance sheets.



	September 30, 2013							December 31, 2012
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related ⁽¹⁾	$	26.8	$	(15.3	)	$	11.5	$	22.4	$	(14.7	)	$	7.7
Contractual service agreements ⁽²⁾	15.6		(1.2		)	14.4		—		—			—
Patents/intellectual property⁽³⁾	3.4		(0.4		)	3.0		7.2		(0.3		)	6.9
Compressed natural gas fueling contract assets ⁽⁴⁾	5.6		(2.3		)	3.3		5.6		(1.3		)	4.3
Renewable energy credits ⁽⁵⁾	5.1		—			5.1		3.1		—			3.1
Nonregulated easements⁽⁶⁾	3.7		(1.1		)	2.6		3.8		(0.9		)	2.9
Customer-owned equipment modifications ⁽⁷⁾	4.0		(0.8		)	3.2		4.0		(0.5		)	3.5
Other	2.6		(0.8		)	1.8		0.5		(0.2		)	0.3
Total	$	66.8	$	(21.9	)	$	44.9	$	46.6	$	(17.9	)	$	28.7

Unamortized intangible assets
MGU trade name	$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
Trillium trade name ⁽⁸⁾	3.5		—			3.5		3.5		—			3.5
Pinnacle trade name ⁽⁸⁾	1.5		—			1.5		1.5		—			1.5
Total intangible assets	$	77.0	$	(21.9	)	$	55.1	$	56.8	$	(17.9	)	$	38.9

⁽¹⁾

Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, ITF's compressed natural gas fueling operations, and Compass Energy Services. See Note 4, "Acquisitions," for more information regarding Integrys Energy Services' acquisition of Compass Energy Services. The remaining weighted-average amortization period for customer-related intangible assets at September 30, 2013, was approximately 11 years.


⁽²⁾	Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at September 30, 2013, was approximately seven years.

⁽³⁾

Represents the fair value of patents/intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. An immaterial adjustment was made to the intangible assets balance in the second quarter of 2013 as a result of a correction to the life of the intangible assets. The remaining amortization period at September 30, 2013, was approximately nine years.


⁽⁴⁾	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at September 30, 2013, was approximately seven years.


⁽⁵⁾	Used at Integrys Energy Services to comply with state Renewable Portfolio Standards and to support customer commitments.


⁽⁶⁾	Relates to easements supporting a pipeline at Integrys Energy Services. The easements are amortized on a straight-line basis, with a remaining amortization period at September 30, 2013, of approximately 11 years.


⁽⁷⁾	Relates to modifications made by Integrys Energy Services and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at September 30, 2013, of approximately 11 years.


⁽⁸⁾	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly-owned subsidiaries of ITF.

Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the three months ended September 30, 2013, and 2012, was $0.6 million and $0.3 million, respectively. Amortization expense for the nine months ended September 30, 2013, and 2012, was $1.5 million and $2.2 million, respectively.

Amortization expense recorded as a component of depreciation and amortization expense in the statements of income for the three months ended September 30, 2013, and 2012, was $1.3 million and $0.5 million, respectively. Amortization expense for the nine months ended September 30, 2013, and 2012, was $3.0 million and $2.0 million, respectively.

An insignificant amount of amortization expense was recorded in discontinued operations for the three and nine months ended September 30, 2013, and 2012.

The following table shows our estimated amortization expense for the next five years, including amounts recorded through September 30, 2013:



	For the Year Ending December 31
(Millions)	2013		2014		2015		2016		2017
Amortization to be recorded in nonregulated cost of sales	$	7.2	$	2.2	$	1.4	$	0.9	$	0.9
Amortization to be recorded in depreciation and amortization expense	4.2		4.3		4.2		4.0		3.9

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NOTE 9 — SHORT-TERM DEBT AND LINES OF CREDIT

Our outstanding short-term borrowings were as follows:



(Millions, except percentages)	September 30, 2013			December 31, 2012
Commercial paper	$	188.0		$	482.4
Average discount rate on commercial paper	0.17		%	0.40		%
Loan under term credit facility	$	200.0		$	—
Average interest rate on loan under term credit facility	0.78		%	—

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2013, and 2012, was $423.0 million and $299.2 million, respectively.

We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our short-term debt and revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities:



(Millions)	Maturity	September 30, 2013		December 31, 2012
Revolving credit facility (Integrys Energy Group)	05/17/2014	$	275.0	$	275.0
Revolving credit facility (Integrys Energy Group)	05/17/2016	200.0		200.0
Revolving credit facility (Integrys Energy Group)	06/13/2017	635.0		635.0
Revolving credit facility (WPS)	05/17/2014	135.0		135.0
Revolving credit facility (WPS)	06/13/2017	115.0		115.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Term credit facility (WPS)	12/31/2013	200.0		—

Total short-term credit capacity		$	1,810.0	$	1,610.0

Less:
Letters of credit issued inside credit facilities		$	37.4	$	25.5
Loan outstanding under term credit facility		200.0		—
Commercial paper outstanding		188.0		482.4

Available capacity under existing agreements		$	1,384.6	$	1,102.1

The loan outstanding under the term credit facility relates to the purchase of Fox Energy Company LLC and must be repaid upon the earlier of WPS's issuance of replacement long-term debt or December 31, 2013. See Note 4, "Acquisitions," for more information regarding this purchase. The commercial paper outstanding at September 30, 2013, had maturity dates ranging from October 1, 2013, through October 7, 2013.

NOTE 10 — LONG-TERM DEBT



(Millions)	September 30, 2013			December 31, 2012
WPS⁽¹⁾	$	850.1		$	872.1
PGL ⁽²⁾	770.0			625.0
NSG ⁽³⁾	88.5			74.5
Integrys Energy Group ⁽⁴⁾	1,074.8			674.8
Total	2,783.4			2,246.4
Unamortized discount on debt	(0.7		)	(1.2		)
Total debt	2,782.7			2,245.2
Less current portion	276.5			313.5
Total long-term debt	$	2,506.2		$	1,931.7


⁽¹⁾	In February 2013, WPS’s $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2013, WPS’s 4.80% Senior Notes will mature. As a result, the $125.0 million balance of these notes was included in the current portion of long-term debt on our balance sheets.


⁽²⁾	In April 2013, PGL bought back its $50.0 million of 5.00% Series KK First and Refunding Mortgage Bonds that were due in February 2033. In the same month, PGL issued $50.0 million of 4.00% Series ZZ First and Refunding Mortgage Bonds. These bonds are due in February 2033.

In May 2013, PGL’s $75.0 million of 4.625% Series NN-2 First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid.

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In August 2013, PGL issued $220.0 million of 3.96% Series AAA First and Refunding Mortgage Bonds. These bonds are due in August 2043.

On November 1, 2013, PGL’s 7.00% Series SS First and Refunding Mortgage Bonds matured. As a result, the $45.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.


⁽³⁾	In May 2013, NSG’s $40.0 million of 4.625% Series N-2 First Mortgage Bonds matured, and the outstanding principal balance was repaid. In the same month, NSG issued $54.0 million of 3.96% Series Q First Mortgage Bonds. These bonds are due in May 2043.

On November 1, 2013, NSG’s 7.00% Series O First Mortgage Bonds matured. As a result, the $6.5 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.


⁽⁴⁾	In August 2013, we issued $400.0 million of Junior Subordinated Notes. Interest is payable quarterly at the stated rate of 6.00% for the first ten years, after which time it changes to a floating rate. These notes are due in August 2073.

In June 2014, our 7.27% Unsecured Senior Notes will mature. As a result, the $100.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at September 30, 2013.

NOTE 11 — INCOME TAXES

We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items.

The table below shows our effective tax rates attributable to continuing operations:



	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012
Effective Tax Rate	31.4	%	28.5	%	36.3	%	32.2	%

Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for multistate income tax obligations. Other significant items that had an impact on our effective tax rates are noted below.

Our effective tax rate for the three months ended September 30, 2013, was lower than the federal statutory tax rate of 35%. This difference was primarily due to a $3.7 million decrease in our provision for income taxes due to the reversal of a regulatory liability. This amount was related to deferred income taxes that had been recorded in prior years as a result of scheduled income tax rate changes in Illinois. We recorded the reversal based on the income tax treatment included in the 2013 final rate order for PGL and NSG.

Our effective tax rate for the three months ended September 30, 2012, was lower than the federal statutory tax rate of 35%. This difference was partially due to a $5.9 million decrease in the provision for income taxes resulting from WPS's 2013 rate case settlement agreement. In the third quarter of 2012, WPS recorded a regulatory asset after the settlement agreement authorized recovery of deferred income taxes expensed in previous years in connection with the 2010 federal health care reform. See Note 21, "Regulatory Environment," for more information. Our effective tax rate was also impacted by the federal income tax benefit of tax credits related to wind production and other miscellaneous tax adjustments.

Our effective tax rate for the nine months ended September 30, 2012, was lower than the federal statutory tax rate of 35%. This difference was partially due to the settlement of certain state income tax examinations and the remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits in 2012. We decreased our provision for income taxes $6.2 million in 2012 primarily related to these items. In addition, our provision for income taxes decreased $5.9 million in 2012 related to the impact of WPS's 2013 rate case settlement agreement, as described above. Our effective tax rate was also impacted by the federal income tax benefit of tax credits related to wind production.

During the three months ended September 30, 2013, there was not a significant change in our liability for unrecognized tax benefits. During the nine months ended September 30, 2013, we decreased our liability for unrecognized tax benefits by $7.7 million. This decrease primarily related to remeasurements of uncertain tax positions driven by an effective settlement of certain state income tax examinations. We reduced the provision for income taxes related to these remeasurements, of which the majority was reported as discontinued operations.

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NOTE 12 — COMMITMENTS AND CONTINGENCIES

(a) Unconditional Purchase Obligations and Purchase Order Commitments

We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The regulated natural gas utilities have obligations to distribute and sell natural gas to their customers, and the regulated electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. Additionally, the majority of the energy supply contracts entered into by Integrys Energy Services are to meet its contractual obligations to deliver energy to customers. The following table shows our minimum future commitments related to these purchase obligations as of September 30, 2013, including those of our subsidiaries.



				Payments Due By Period
(Millions)	Date Contracts Extend Through	Total Amounts Committed		2013		2014		2015		2016		2017		Later Years
Natural gas utility supply and transportation	2028	$	839.8	$	48.5	$	171.0	$	162.4	$	148.5	$	103.4	$	206.0
Electric utility
Purchased power	2029	795.5		37.6		66.5		32.6		28.8		27.7		602.3
Coal supply and transportation	2018	110.6		17.3		44.4		31.9		9.5		6.0		1.5
Nonregulated electricity and natural gas supply	2020	634.6		150.0		329.7		111.4		36.0		6.1		1.4
Total		$	2,380.5	$	253.4	$	611.6	$	338.3	$	222.8	$	143.2	$	811.2

We and our subsidiaries also had commitments of $770.9 million in the form of purchase orders issued to various vendors at September 30, 2013, that relate to normal business operations, including construction projects.

(b) Environmental Matters

Air Permitting Violation Claims

Weston and Pulliam Clean Air Act (CAA) Issues:

In November 2009, the EPA issued a Notice of Violation (NOV) to WPS alleging violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes:


•	the installation of emission control technology, including ReACT™, on Weston 3,


•	changed operating conditions (including refueling, repowering, and/or retirement of units),


•	limitations on plant emissions,


•	beneficial environmental projects totaling $6.0 million (various options, including capital projects, are available), and


•	a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. As of September 30, 2013, no decision had been made on how to address this requirement. Therefore, retirement of the Weston and Pulliam units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

In May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of September 30, 2013. It is unknown whether the Sierra Club will take further action in the future.

Columbia and Edgewater CAA Issues:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleges violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric (Joint Owners) reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the Court in June 2013, after a public comment period. The final Consent Decree includes:


•	the installation of emission control technology, including scrubbers at the Columbia plant,


•	changed operating conditions (including refueling, repowering, and/or retirement of units),


•	limitations on plant emissions,

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•	beneficial environmental projects, with WPS's portion totaling $1.3 million (various options, including capital projects, are available), and


•	WPS's portion of a civil penalty and legal fees totaling $0.4 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain of the Columbia and Edgewater units. As of September 30, 2013, no decision had been made on how to address this requirement. Therefore, retirement of the Columbia and Edgewater units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA. A similar case had also been filed by the Sierra Club related to the Columbia plant but was dismissed without prejudice due to the impending settlement and Consent Decree. As part of the Consent Decree settlement, the Sierra Club filed a new lawsuit related to the Columbia plant, which gave notice of the filing of the Consent Decree. Both Sierra Club lawsuits against WP&L were dismissed when the Consent Decree was approved by the Court.

Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit for the Weston 4 plant. WPS objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR and met with the WDNR to resolve these issues. In September 2011, the WDNR issued an updated draft revised permit and a request for public comments. Due to the significance of the changes to the draft revised permit, the WDNR re-issued the draft revised permit for additional comments in February 2013. In July 2012, Clean Wisconsin filed a lawsuit against the WDNR alleging failure to issue or delay in issuing the Weston Title V permit. WPS and the WDNR both filed motions to dismiss Clean Wisconsin's lawsuit, which the Court granted in February 2013. Clean Wisconsin appealed this decision but voluntarily filed a dismissal of its appeal in July 2013, closing the lawsuit. The dismissal resulted from the WDNR sending the proposed permit to the EPA for action. Later in July 2013, the WDNR issued the air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also filed Petitions for Review and requests for contested case proceedings regarding various aspects of the permit. On October 14, 2013, the WDNR granted all parties' requests for contested case proceedings, except one issue where they asked for clarifying information from WPS. The Petitions for Review, by all parties, have been stayed pending the resolution of the contested cases.

Columbia Title V Air Permit:

In February 2011, the Sierra Club filed a lawsuit against the EPA seeking to have the EPA take over the Title V permit process from the WDNR for the Columbia plant. The Sierra Club alleged the EPA must now act on the reconsideration of the Title V permit since the WDNR has exceeded its time frame in which to respond to an EPA order issued in 2009. In May 2011, the WDNR issued a revised draft Title V permit in response to the EPA's order. In June 2012, WP&L received notice from the EPA of the EPA's proposal for WP&L to apply for a federally-issued Title V permit since the WDNR had not addressed the EPA's objections to the Title V permit issued for the Columbia plant. Based on the entry of the Consent Decree, which covers the Columbia plant, the EPA has withdrawn its order, and this matter is now closed. This matter did not have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, WPS received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant and Weston 1, Weston 2, and Weston 4 individually. WPS also received an NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions were taken for the events in the five NOVs. In December 2011, the WDNR referred several of the claims in the NOVs to the state Justice Department for enforcement. In August 2013, WPS and the state Justice Department reached a settlement on these claims, which did not have a material impact on our financial statements.

Weston 4 Construction Permit

From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits. In July 2010, WPS, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court. In March 2011, the Wisconsin Supreme Court denied all Petitions for Review. Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved. WPS is working with the WDNR to resolve this issue as part of the current Title V air permit issued in July 2013 and subsequent proceedings discussed above. We do not expect this matter to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin's mercury rule requires a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level

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defined by the Best Available Control Technology rule. As of September 30, 2013, WPS estimates capital costs of approximately $9 million for its wholly owned plants to achieve the required reductions. The capital costs are expected to be recovered in future rates.

In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. The State of Wisconsin is in the process of revising the compliance date in the state mercury rules to be consistent with the MATS rule. We are currently evaluating options for achieving the emission limits specified in this rule, but we do not anticipate the cost of compliance to be significant. We expect to recover future compliance costs in future rates.

Sulfur Dioxide and Nitrogen Oxide:

In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. In October 2012, the EPA and several other parties filed petitions for a rehearing of the D.C. Circuit's decision, which the D.C. Circuit denied in January 2013. In March 2013, the EPA requested that the United States Supreme Court (Supreme Court) review the D.C. Circuit's rejection of CSAPR. In June 2013, the Supreme Court agreed to review the case, but a decision is not expected until 2014.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART), and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR's modeling has shown the impairment to be so insignificant that additional capital expenditures on controls may not be warranted.

Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether WPS will have to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. WPS expects to recover any future compliance costs in future rates. The potential impact on Integrys Energy Services is not expected to be material.

Manufactured Gas Plant Remediation

Our natural gas utilities, their predecessors, and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, our natural gas utilities are required to undertake remedial action with respect to some of these materials. They are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a "multi-site" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

Our natural gas utilities are responsible for the environmental remediation of 53 sites, of which 20 have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA's program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. As of September 30, 2013, we estimated and accrued for $612.1 million of future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of September 30, 2013, cash expenditures for environmental remediation not yet recovered in rates were $46.2 million. We recorded a regulatory asset of $658.3 million at September 30, 2013, which is net of insurance recoveries received of $64.9 million, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

NOTE 13 — GUARANTEES

The following table shows our outstanding guarantees:



	Total Amounts Committed		Expiration
(Millions)	at September 30, 2013		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	605.9	$	390.3	$	2.7	$	212.9
Standby letters of credit⁽²⁾	40.8		40.7		0.1		—
Surety bonds⁽³⁾	20.6		15.6		5.0		—
Other guarantees⁽⁴⁾	23.5		—		—		23.5
Total guarantees	$	690.8	$	446.6	$	7.8	$	236.4

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⁽¹⁾	Consists of (a) $438.3 million, $5.0 million, and $2.0 million to support the business operations of Integrys Energy Services, IBS, and UPPCO, respectively, and (b) $110.5 million and $50.1 million related to natural gas supply at MERC and MGU, respectively. These guarantees are not reflected on our balance sheets.

⁽²⁾

At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $38.8 million issued to support Integrys Energy Services’ operations and $2.0 million issued to support ITF, MERC, MGU, NSG, PGL, UPPCO, and WPS. These amounts are not reflected on our balance sheets.


⁽³⁾	Primarily for the construction and operation of compressed natural gas fueling stations, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.

⁽⁴⁾

Consists of (a) $10.0 million related to the sale agreement for Integrys Energy Services’ Texas retail marketing business, which included a number of customary representations, warranties, and indemnification provisions. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (b) $5.0 million related to an environmental indemnification provided by Integrys Energy Services as part of the sale of the Stoneman generation facility, under which we expect that the likelihood of required performance is remote; (c) $2.4 million related to the performance of an operating and maintenance agreement by ITF; and (d) $6.1 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (b), (c), and (d) above are not reflected on our balance sheets.

We have provided total parental guarantees of $496.0 million on behalf of Integrys Energy Services. Our exposure under these guarantees related to existing transactions at September 30, 2013, was approximately $245.8 million.

NOTE 14 — EMPLOYEE BENEFIT PLANS

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:



	Pension Benefits												Other Postretirement Benefits
	Three Months Ended September 30						Nine Months Ended September 30						Three Months Ended September 30						Nine Months Ended September 30
(Millions)	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	7.5		$	11.5		$	22.6		$	34.5		$	6.3		$	5.2		$	18.7		$	15.6
Interest cost	17.8			19.5			53.4			58.5			6.2			7.1			18.6			21.4
Expected return on plan assets	(26.4		)	(27.0		)	(79.1		)	(80.9		)	(7.7		)	(7.1		)	(23.0		)	(21.2		)
Amortization of transition obligation	—			—			—			—			—			0.1			—			0.2
Amortization of prior service cost (credit)	1.0			1.3			3.0			3.8			(0.7		)	(0.9		)	(1.9		)	(2.6		)
Amortization of net actuarial loss	14.2			8.5			42.5			25.5			2.1			1.7			6.3			5.0
Net periodic benefit cost	$	14.1		$	13.8		$	42.4		$	41.4		$	6.2		$	6.1		$	18.7		$	18.4

Transition obligations, prior service costs (credits), and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are included in accumulated OCI for our nonregulated entities and are recorded as net regulatory assets for our utilities.

We make contributions to our plans in accordance with legal and tax requirements. These contributions do not necessarily occur evenly throughout the year. During the nine months ended September 30, 2013, we contributed $64.9 million to our pension plans and $0.1 million to our other postretirement benefit plans. We expect to contribute an additional $3.4 million to our pension plans and $32.8 million to our other postretirement benefit plans during the remainder of 2013, dependent upon various factors affecting us, including our liquidity position and tax law changes.

NOTE 15 — STOCK-BASED COMPENSATION

The following table reflects the stock-based compensation expense and the related deferred tax benefit recognized in income for the three and nine months ended September 30:



	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2013		2012		2013		2012
Stock options	$	0.5	$	0.5	$	1.4	$	1.5
Performance stock rights	1.2		0.5		4.4		4.8
Restricted share units	2.5		2.1		7.8		7.5
Nonemployee director deferred stock units	0.2		—		0.7		1.0
Total stock-based compensation expense	$	4.4	$	3.1	$	14.3	$	14.8
Deferred income tax benefit	$	1.8	$	1.2	$	5.7	$	5.9

No stock-based compensation cost was capitalized during the three and nine months ended September 30, 2013 and 2012.

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Stock Options

The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is derived from the output of the binomial lattice model and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using the 10-year historical volatility of our stock price. The following table shows the weighted-average fair value per stock option granted during the nine months ended September 30, 2013, along with the assumptions incorporated into the valuation model:



		February 2013 Grant
Weighted-average fair value per option		$6.03
Expected term		5 years
Risk-free interest rate		0.18% – 2.11%
Expected dividend yield		5.33%
Expected volatility		24%

A summary of stock option activity for the nine months ended September 30, 2013, and information related to outstanding and exercisable stock options at September 30, 2013, is presented below:



	Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2012	2,046,355		$	49.25
Granted	319,234		56.00
Exercised	(793,455	)	48.58
Forfeited	(15,510	)	56.00
Outstanding at September 30, 2013	1,556,624		$	50.91	6.5	$	8.2
Exercisable at September 30, 2013	816,336		$	49.92	4.8	$	5.3

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options on September 30, 2013. This is calculated as the difference between our closing stock price on September 30, 2013, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the nine months ended September 30, 2013, and 2012, was $9.0 million and $10.8 million, respectively. The actual tax benefit realized for the tax deductions from these option exercises for the nine months ended September 30, 2013, and 2012, was $3.6 million and $4.4 million, respectively.

As of September 30, 2013, $1.5 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 2.0 years.

Performance Stock Rights

The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. The expected volatility is estimated using two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at September 30:



		2013
Risk-free interest rate		0.26% – 1.27%
Expected dividend yield		5.18% – 5.34%
Expected volatility		19% – 36%

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A summary of the activity for the nine months ended September 30, 2013, related to performance stock rights accounted for as equity awards is presented below:



	Performance Stock Rights		Weighted-Average Fair Value ⁽²⁾
Outstanding at December 31, 2012	108,314		$	65.38
Granted	22,636		48.50
Award modifications ⁽¹⁾	28,789		39.80
Distributed	(94,758	)	72.36
Adjustment for final payout	21,867		72.36
Forfeited	(1,099	)	48.50
Outstanding at September 30, 2013	85,749		$	46.62

⁽¹⁾ Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in our common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification.


⁽²⁾	Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

The weighted-average grant date fair value of performance stock rights awarded during the nine months ended September 30, 2013, and 2012, was $48.50 and $52.70, per performance stock right, respectively.

A summary of the activity for the nine months ended September 30, 2013, related to performance stock rights accounted for as liability awards is presented below:



	Performance Stock Rights
Outstanding at December 31, 2012	189,093
Granted	90,496
Award modifications *	(28,789	)
Distributed	(61,753	)
Adjustment for final payout	14,255
Forfeited	(4,398	)
Outstanding at September 30, 2013	198,904

Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in our common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification.

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of September 30, 2013, was $47.32 per performance stock right.

As of September 30, 2013, $3.0 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.5 years.

The total intrinsic value of performance stock rights distributed during the nine months ended September 30, 2013, and 2012, was $8.8 million and $4.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights during the nine months ended September 30, 2013, and 2012, was $3.6 million and $1.9 million, respectively.

Restricted Share Units

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the nine months ended September 30, 2013, is presented below:



	Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2012	505,690		$	48.38
Granted	196,894		55.93
Dividend equivalents	17,830		52.19
Vested and released	(207,411	)	46.32
Forfeited	(5,997	)	53.16
Outstanding at September 30, 2013	507,006		$	52.24

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As of September 30, 2013, $12.6 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.3 years.

The total intrinsic value of restricted share unit awards vested and released during the nine months ended September 30, 2013, and 2012, was $11.6 million and $10.5 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the nine months ended September 30, 2013, and 2012, was $4.7 million and $4.2 million respectively.

The weighted-average grant date fair value of restricted share units awarded during the nine months ended September 30, 2013, and 2012, was $55.93 and $53.24 per unit, respectively.

Nonemployee Directors Deferred Stock Units

Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on December 31 of the prior year. Prior to January 1, 2013, under the terms of the agreement, these awards vested immediately, and therefore were expensed on the grant date. Beginning in 2013, these awards generally vest over one year. Therefore, the expense for these awards is recognized pro-rata over the year in which the grant occurs.

NOTE 16 — COMMON EQUITY

We had the following changes to issued common stock during the nine months ended September 30, 2013:



Common stock issued at December 31, 2012		78,287,906
Shares issued
Stock-based compensation		1,144,495
Stock Investment Plan		219,847
Rabbi trust shares		105,467
Common stock issued at September 30, 2013		79,757,715

The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:



Period		Method of meeting requirements
Beginning 02/05/2013		Issuing new shares *
01/01/2012 – 02/04/2013		Purchased shares on the open market


*	These stock issuances increased equity $71.1 million in 2013.

The following table reconciles common shares issued and outstanding:



	September 30, 2013			December 31, 2012
	Shares	Average Cost *		Shares	Average Cost *
Common stock issued	79,757,715			78,287,906
Less:
Deferred compensation rabbi trust	467,967	$	48.42	385,439	$	46.03
Total common shares outstanding	79,289,748			77,902,467


*	Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.

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Earnings Per Share

Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, and certain shares issuable under the deferred compensation plan. To the extent these items are accounted for as liability awards, the numerator is adjusted for any changes in income or loss that would have resulted had the awards been accounted for as equity awards during the period. The following table reconciles our computation of basic and diluted earnings per share:



	Three Months Ended September 30						Nine Months Ended September 30
(Millions, except per share amounts)	2013			2012			2013			2012
Numerator:
Net income from continuing operations	$	39.4		$	74.3		$	217.7		$	224.8
Discontinued operations, net of tax	(0.6		)	(8.0		)	4.7			(9.2		)
Preferred stock dividends of subsidiary	(0.7		)	(0.7		)	(2.3		)	(2.3		)
Noncontrolling interest in subsidiaries	—			0.1			0.1			0.1
Net income attributed to common shareholders — basic	$	38.1		$	65.7		$	220.2		$	213.4
Effect of dilutive securities
Stock-based compensation	(0.1		)	—			(0.1		)	—
Net income attributed to common shareholders — diluted	$	38.0		$	65.7		$	220.1		$	213.4

Denominator:
Average shares of common stock — basic	79.8			78.5			79.3			78.5
Effect of dilutive securities
Stock-based compensation	0.4			0.6			0.4			0.6
Deferred compensation	—			0.2			0.2			0.2
Average shares of common stock — diluted	80.2			79.3			79.9			79.3

Earnings per common share
Basic	$	0.48		$	0.84		$	2.78		$	2.72
Diluted	0.47			0.83			2.76			2.69

The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:



	Three Months Ended September 30		Nine Months Ended September 30
(Millions)	2013	2012	2013	2012
Stock-based compensation	0.4	0.9	0.2	0.6
Deferred compensation	0.2	—	0.1	—

Dividend Restrictions

Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our regulated utility subsidiaries to transfer funds to us in the form of dividends. Our regulated utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly.

The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.

NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.

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We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At September 30, 2013, these covenants did not restrict the payment of any dividends beyond the amount restricted under our subsidiary requirements described above.

As of September 30, 2013, total restricted net assets were $1,743.4 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $138.2 million at September 30, 2013.

We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Capital Transactions with Subsidiaries

During the nine months ended September 30, 2013, capital transactions with subsidiaries were as follows (in millions):



Subsidiary	Dividends To Parent		Return Of Capital To Parent		Equity Contributions From Parent
ITF ⁽¹⁾	$	—	$	—	$	25.2
MERC	—		21.0		3.5
MGU	—		12.5		5.0
UPPCO	—		5.5		—
WPS	81.5		35.0		200.0
WPS Investments, LLC ⁽²⁾	52.7		—		10.2
Total	$	134.2	$	74.0	$	243.9


⁽¹⁾	ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.

⁽²⁾

WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At September 30, 2013, we had an 86.13% ownership interest, while WPS and UPPCO had an 11.44% and 2.43% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2013, all equity contributions to WPS Investments, LLC were made solely by us.

NOTE 17 — ACCUMULATED OTHER COMPREHENSIVE LOSS

The following tables show the changes, net of tax, to our accumulated other comprehensive loss during the three and nine months ended September 30, 2013:



Three Months Ended September 30, 2013							Accumulated Other Comprehensive Income (Loss)
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at June 30, 2013	$	(2.1	)	$	(34.5	)	$	(36.6	)
Amounts reclassified out of accumulated other comprehensive loss	0.3			0.6			0.9
Ending balance at September 30, 2013	$	(1.8	)	$	(33.9	)	$	(35.7	)



Nine Months Ended September 30, 2013							Accumulated Other Comprehensive Income (Loss)
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2012	$	(5.2	)	$	(35.7	)	$	(40.9	)
Other comprehensive income before reclassifications	0.7			—			0.7
Amounts reclassified out of accumulated other comprehensive loss	2.7			1.8			4.5
Net current period other comprehensive income	3.4			1.8			5.2
Ending balance at September 30, 2013	$	(1.8	)	$	(33.9	)	$	(35.7	)

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The following table shows the reclassifications out of accumulated other comprehensive loss during the three and nine months ended September 30, 2013:



	Amount Reclassified
	Three Months Ended			Nine Months Ended
(Millions)	September 30, 2013			September 30, 2013			Affected Line Item in the Statements of Income
Losses on cash flow hedges
Utility commodity derivative contracts	$	—		$	0.2		Operating and maintenance expense⁽¹⁾
Nonregulated commodity derivative contracts	0.2			3.4			Nonregulated revenues
Interest rate hedges	0.3			0.8			Interest expense
	0.5			4.4			Total before tax
	0.2			1.7			Tax expense
	0.3			2.7			Net of tax

Defined benefit plans
Amortization of prior service costs	(0.1		)	(0.2		)	⁽²⁾
Amortization of net actuarial losses	1.1			3.2			⁽²⁾
	1.0			3.0			Total before tax
	0.4			1.2			Tax expense
	0.6			1.8			Net of tax
Total reclassifications	$	0.9		$	4.5


⁽¹⁾	This item relates to changes in the price of natural gas used to support utility operations.


⁽²⁾	These items are included in the computation of net periodic benefit cost. See Note 14, "Employee Benefit Plans," for additional information.

NOTE 18 — VARIABLE INTEREST ENTITIES

In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF is the primary beneficiary, which requires us to consolidate the assets, liabilities, and statements of income of the joint venture. At September 30, 2013, and December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of AMP Trillium LLC assets and liabilities included on our balance sheets were also not significant.

In 2011, ITF formed Integrys PTI CNG Fuels LLC as a joint venture with Paper Transport Inc. The joint venture was established to own and operate compressed natural gas fueling stations. ITF and Paper Transport Inc. each initially owned 50% of the joint venture. We determined that the joint venture was a variable interest entity and that ITF was the primary beneficiary, which required us to consolidated the assets, liabilities, and statements of income of the joint venture. At December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. The carrying amounts of Integrys PTI CNG Fuels LLC assets and liabilities included on our December 31, 2012, balance sheet were also not significant. In June 2013, ITF purchased Paper Transport Inc.'s 50% ownership interest of the joint venture, and it became a wholly-owned subsidiary.

We have a variable interest in an entity through a power purchase agreement at UPPCO that reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under this agreement. This contract for 17.5 megawatts of capacity expires in 2014. We evaluated this variable interest entity for possible consolidation. We considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plant and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of the variable interest entity. At September 30, 2013, and December 31, 2012, the assets and liabilities on our balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with the contract. There is not a significant potential exposure to loss as a result of involvement with the variable interest entity.

We also had a variable interest in Fox Energy Company LLC through a power purchase agreement at WPS that contained a tolling arrangement related to the cost of fuel. In connection with the purchase of Fox Energy Company LLC in March 2013, WPS paid $50.0 million for the early termination of this 500-megawatt agreement. See Note 4, "Acquisitions," for more information regarding this purchase. We evaluated this variable interest entity for possible consolidation and determined that consolidation was not required since we were not the primary beneficiary of the variable interest entity. The assets and liabilities on our December 31, 2012, balance sheet that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power.

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NOTE 19 — FAIR VALUE

Fair Value Measurements

A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities.

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methodologies.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts include inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), price correlation (for cross commodity contracts), probability of default, and time value. These inputs are available through multiple sources, including brokers and over-the-counter and online exchanges. Transactions valued using these inputs are classified in Level 2.

Certain assets and liabilities are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:


•	While forward price curves may have been based on observable information, significant assumptions may have been made regarding monthly shaping and locational basis differentials.


•	Certain transactions were valued using price curves that extended beyond an observable period. Assumptions were made to extrapolate prices from the last observable period through the end of the transaction term, primarily through the use of historically settled data or correlations to other locations.

We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from any of the trading functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.

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The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:



	September 30, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.9	$	1.8	$	—	$	2.7
Financial transmission rights (FTRs)	—		—		3.4		3.4
Coal contracts	—		—		1.5		1.5
Nonregulated Segments
Natural gas contracts	9.9		42.3		21.3		73.5
Electric contracts	70.1		49.0		12.8		131.9
Total Risk Management Assets	$	80.9	$	93.1	$	39.0	$	213.0

Investment in exchange-traded funds	$	13.4	$	—	$	—	$	13.4

Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	0.8	$	5.2	$	—	$	6.0
Petroleum product contracts	0.2		—		—		0.2
FTRs	—		—		0.4		0.4
Coal contracts	—		—		2.7		2.7
Nonregulated Segments
Natural gas contracts	16.0		26.5		9.7		52.2
Electric contracts	75.6		69.9		10.1		155.6
Total Risk Management Liabilities	$	92.6	$	101.6	$	22.9	$	217.1

Contingent consideration related to the acquisition of Compass Energy Services (Compass) *	$	—	$	—	$	7.7	$	7.7


*	See Note 4, "Acquisitions," for more information.



	December 31, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.3	$	3.1	$	—	$	3.4
FTRs	—		—		2.1		2.1
Petroleum product contracts	0.2		—		—		0.2
Coal contracts	—		—		2.5		2.5
Nonregulated Segments
Natural gas contracts	21.4		36.4		5.4		63.2
Electric contracts	48.4		61.3		9.6		119.3
Total Risk Management Assets	$	70.3	$	100.8	$	19.6	$	190.7

Investment in exchange-traded funds	$	11.8	$	—	$	—	$	11.8

Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.1	$	14.1	$	—	$	15.2
FTRs	—		—		0.1		0.1
Coal contracts	—		—		9.0		9.0
Nonregulated Segments
Natural gas contracts	17.7		36.9		1.5		56.1
Electric contracts	54.9		91.1		13.9		159.9
Total Risk Management Liabilities	$	73.7	$	142.1	$	24.5	$	240.3

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The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. For more information on derivative instruments, see Note 3, "Risk Management Activities."

The following tables show net risk management assets (liabilities) transferred between the levels of the fair value hierarchy:



	Nonregulated Segments — Natural Gas Contracts
	Three Months Ended September 30, 2013						Three Months Ended September 30, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		0.3		$	—	N/A		0.3
Transfers into Level 3 from	—		2.5		N/A		—		0.4		N/A



	Nonregulated Segments — Natural Gas Contracts
	Nine Months Ended September 30, 2013						Nine Months Ended September 30, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		0.3		$	—	N/A		1.7
Transfers into Level 3 from	—		4.0		N/A		—		3.2		N/A



	Nonregulated Segments — Electric Contracts
	Three Months Ended September 30, 2013								Three Months Ended September 30, 2012
(Millions)	Level 1			Level 2		Level 3			Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A			$	—	$	—		N/A		$	—	$	—
Transfers into Level 2 from	$	—		N/A		(0.8		)	$	—	N/A		(1.9		)
Transfers into Level 3 from	(0.2		)	—		N/A			—		1.0		N/A



	Nonregulated Segments — Electric Contracts
	Nine Months Ended September 30, 2013						Nine Months Ended September 30, 2012
(Millions)	Level 1			Level 2		Level 3	Level 1		Level 2			Level 3
Transfers into Level 1 from	N/A			$	—	—	N/A		$	—		$	—
Transfers into Level 2 from	$	—		N/A		4.6	$	—	N/A			(5.8		)
Transfers into Level 3 from	(0.2		)	6.2		N/A	—		(7.8		)	N/A

Derivatives are transferred between the levels of the fair value hierarchy primarily due to changes in the source of data used to construct price curves as a result of changes in market liquidity. We recognize transfers between the levels at the value as of the end of the reporting period.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at September 30, 2013. The amounts and percentages listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a transaction to be classified as Level 3.



	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
Utility Segments
FTRs	$	3.4	$	0.4	Market-based	Forward market prices ($/megawatt-month)⁽¹⁾	$180.59
Coal contracts	1.5		2.7		Market-based	Forward market prices ($/ton) ⁽²⁾	$12.21 — $14.63
Nonregulated Segments
Natural gas contracts	21.3		9.7		Market-based	Forward market prices ($/dekatherm)⁽³⁾	($2.36) — $8.17
						Probability of default⁽⁴⁾	11.6% — 51.0%
Electric contracts	12.8		10.1		Market-based	Forward market prices ($/megawatt-hours) ⁽³⁾	($7.15) — $9.25
						Probability of default⁽⁴⁾	26.0	%
						Option volatilities⁽⁵⁾	19.3% — 118.0%
						Monthly curve shaping⁽⁶⁾	(37.5)% — 25.6%
Contingent consideration related to the acquisition of Compass	N/A		7.7		Monte Carlo analysis	Growth rate⁽⁷⁾	(32)% — 157%


⁽¹⁾	Represents forward market prices developed using historical cleared pricing data from MISO.


⁽²⁾	Represents third-party forward market pricing.


⁽³⁾	Represents unobservable basis spreads developed using historical settled prices that are applied to observable market prices at various natural gas and electric locations, as well as unobservable adjustments made to extend observable market prices beyond the quoted period through the end of the transaction term.

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⁽⁴⁾	Based on Moody's one-year counterparty default percentages.


⁽⁵⁾	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model using volatility curves from third parties.


⁽⁶⁾	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.


⁽⁷⁾	Represents the range of assumed growth rates of earnings before interest, taxes, and amortization input into the valuation model.

Significant changes in historical settlement prices, forward commodity prices, and option volatilities would result in a directionally similar significant change in fair value. Significant changes in probability of default would result in a significant directionally opposite change in fair value. Changes in the adjustments to prices related to monthly curve shaping would affect fair value differently depending on their direction. A significant decrease in the growth rate used to value the contingent consideration would result in a directionally similar significant change in fair value. A significant increase in the growth rate would not have a significant impact on the fair value as the contingent consideration is limited to $8.0 million.

The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:



Three Months Ended September 30, 2013	Nonregulated Segments									Utility Segments
(Millions)	Natural Gas			Electric			Contingent Consideration*			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	7.7		$	4.1		$	(7.7	)	$	3.9		$	(2.3	)	$	5.7
Net realized and unrealized gains included in earnings	4.2			1.9			—			1.3			—			7.4
Net unrealized gains (losses) recorded as regulatory assets or liabilities	—			—			—			0.6			(4.5		)	(3.9		)
Purchases	—			0.7			—			—			—			0.7
Settlements	(2.5		)	(4.6		)	—			(2.8		)	5.6			(4.3		)
Net transfers into Level 3	2.5			(0.2		)	—			—			—			2.3
Net transfers out of Level 3	(0.3		)	0.8			—			—			—			0.5
Balance at the end of the period	$	11.6		$	2.7		$	(7.7	)	$	3.0		$	(1.2	)	$	8.4

Net unrealized gains included in earnings related to instruments still held at the end of the period	$	4.2		$	1.9		$	—		$	—		$	—		$	6.1


*	Represents the contingent consideration related to the acquisition of Compass. See Note 4 "Acquisitions," for more information.



Nine Months Ended September 30, 2013	Nonregulated Segments									Utility Segments
(Millions)	Natural Gas			Electric			Contingent Consideration*			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	3.9		$	(4.3	)	$	—		$	2.0		$	(6.5	)	$	(4.9	)
Net realized and unrealized gains included in earnings	1.3			7.6			—			1.7			—			10.6
Net unrealized (losses) gains recorded as regulatory assets or liabilities	—			—			—			(0.3		)	2.2			1.9
Purchases	7.0			2.3			(7.7		)	4.9			—			6.5
Sales	—			—			—			(0.1		)	—			(0.1		)
Settlements	(4.3		)	(4.3		)	—			(5.2		)	3.1			(10.7		)
Net transfers into Level 3	4.0			6.0			—			—			—			10.0
Net transfers out of Level 3	(0.3		)	(4.6		)	—			—			—			(4.9		)
Balance at the end of the period	$	11.6		$	2.7		$	(7.7	)	$	3.0		$	(1.2	)	$	8.4

Net unrealized gains included in earnings related to instruments still held at the end of the period	$	1.3		$	7.6		$	—		$	—		$	—		$	8.9


*	Represents the contingent consideration related to the acquisition of Compass. See Note 4 "Acquisitions," for more information.

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Three Months Ended September 30, 2012	Nonregulated Segments							Utility Segments
(Millions)	Natural Gas			Electric				FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	6.3		$	(14.7	)		$	4.8		$	(9.8	)	$	(13.4	)
Net realized and unrealized gains (losses) included in earnings	2.7			2.6			*	(1.0		)	—			4.3
Net unrealized (losses) gains recorded as regulatory assets or liabilities	—			—				(0.2		)	2.1			1.9
Settlements	(6.7		)	(0.1		)		(0.4		)	(1.6		)	(8.8		)
Net transfers into Level 3	0.4			1.0				—			—			1.4
Net transfers out of Level 3	(0.3		)	1.9				—			—			1.6
Balance at the end of the period	$	2.4		$	(9.3	)		$	3.2		$	(9.3	)	$	(13.0	)

Net unrealized gains included in earnings related to instruments still held at the end of the period	$	2.7		$	2.6		^*	$	—		$	—		$	5.3


*	Includes a $0.2 million net unrealized loss reported as discontinued operations. See Note 5, "Discontinued Operations," for more information.



Nine Months Ended September 30, 2012	Nonregulated Segments							Utility Segments
(Millions)	Natural Gas			Electric				FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	8.3		$	(11.5	)		$	2.2		$	(6.9	)	$	(7.9	)
Net realized and unrealized gains (losses) included in earnings	1.9			(5.3		)	*	1.5			—			(1.9		)
Net unrealized gains recorded as regulatory assets or liabilities	—			—				0.1			1.5			1.6
Purchases	—			2.1				4.9			—			7.0
Sales	—			—				(0.1		)	—			(0.1		)
Settlements	(9.3		)	7.4				(5.4		)	(3.9		)	(11.2		)
Net transfers into Level 3	3.2			(7.8		)		—			—			(4.6		)
Net transfers out of Level 3	(1.7		)	5.8				—			—			4.1
Balance at the end of the period	$	2.4		$	(9.3	)		$	3.2		$	(9.3	)	$	(13.0	)

Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	1.9		$	(5.3	)	^*	$	—		$	—		$	(3.4	)


*	Includes a $0.6 million net unrealized loss reported as discontinued operations. See Note 5, "Discontinued Operations," for more information.

Realized and unrealized gains and losses included in earnings related to Integrys Energy Services’ risk management assets and liabilities are recorded through nonregulated revenue or nonregulated cost of sales on the statements of income, depending on the nature of the instrument. Unrealized gains and losses on Level 3 derivatives at the utilities are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through utility cost of fuel, natural gas, and purchased power on the statements of income.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:



	September 30, 2013				December 31, 2012
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,782.7	$	2,768.5	$	2,245.2	$	2,425.8
Preferred stock of subsidiary	51.1		61.6		51.1		52.7

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.

Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each of these items approximates fair value.

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NOTE 20 — ADVERTISING COSTS

Costs associated with certain natural gas and electric direct-response advertising campaigns at Integrys Energy Services were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $5.2 million and $5.5 million as of September 30, 2013, and December 31, 2012, respectively. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. We did not record any significant impairments during the three and nine months ended September 30, 2013, and 2012.

Direct-response advertising costs are amortized to operating and maintenance expense over the estimated period of benefit, which is approximately two years. The amortization of direct-response advertising costs was $0.1 million and $1.0 million for the three months ended September 30, 2013, and 2012, respectively. The amortization of direct-response advertising costs was $4.1 million and $2.3 million for the nine months ended September 30, 2013, and 2012, respectively.

We expense all advertising costs as incurred, except for those capitalized as direct-response advertising, as discussed above. Other advertising expense was $2.2 million and $2.1 million, for the three months ended September 30, 2013, and 2012, respectively. Other advertising expense was $6.6 million and $5.2 million, for the nine months ended September 30, 2013, and 2012, respectively.

NOTE 21 — REGULATORY ENVIRONMENT

Wisconsin

2014 Rate Case

In March 2013, WPS filed an application with the PSCW to increase retail electric and natural gas rates $71.1 million and $19.0 million, respectively, with rates proposed to be effective January 1, 2014. The filing includes a request for a 10.75% return on common equity and a common equity ratio of 51.11% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the purchase and operation of the Fox Energy Center, the completion of a one-time fuel refund to customers in 2013, increased electric transmission costs, additional construction related to the installation of environmental controls and the improvement of electric reliability, the recovery of pension and other employee benefit costs deferred in 2013 rates, and general inflation. Partially offsetting these increases are lower purchased power capacity costs and a refund to customers resulting from WPS's decoupling mechanism. The proposed retail natural gas rate increase is generally the result of the recovery of amounts related to decoupling, increased costs of inspecting natural gas lines for safety, the recovery of pension and other employee benefit costs deferred in 2013 rates, and general inflation.

In August 2013, the PSCW Staff submitted testimony and recommended rate increases of $9.3 million and $7.8 million for retail electric and natural gas, respectively, reflecting a 10.20% return on common equity. Their recommendation also included a common equity ratio of 50.14% in WPS's regulatory capital structure. The PSCW held both technical and public hearings in September 2013. In October 2013, WPS issued an initial brief revising its requested retail electric and natural gas rate increases to approximately $60 million and approximately $14 million, respectively, including a reduced return on common equity of 10.60%. Included in these revised amounts, is WPS's request for recovery of $1.7 million for the Wisconsin retail allocation of environmental remediation capital and operating costs related to WPS's Consent Decree with the EPA. See Note 12, "Commitments and Contingencies," for more information. Finally, WPS requested the removal of the annual caps associated with the decoupling mechanism that is currently in place. WPS's revised request is a result of WPS's current position on contested issues. New rates are expected to be effective January 1, 2014.

2013 Rates

In December 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement included a $28.5 million imputed retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase is being deferred for recovery in a future rate proceeding. As a result, there was no change to customers' 2013 retail electric rates. The settlement agreement also included a $3.4 million retail natural gas rate decrease, which included a deferral of $2.1 million of pension and other employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were reduced based on updated December 31, 2012, pension and other employee benefit cost estimates, which were filed with the PSCW in March 2013. The settlement agreement reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The settlement agreement also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. Lastly, the settlement agreement authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek Wind Project.

A new decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism is based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism does not cover all customer classes, and it continues to include an annual $14.0 million cap for electric service and

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an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate proceeding.

2012 Rates

In December 2011, the PSCW issued a final written order for WPS, effective January 1, 2012. It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million. The electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% price variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs.

Michigan

2014 MGU Rate Case

In October 2013, MGU entered into a settlement agreement with the MPSC and all other involved parties resolving all issues in the MGU 2014 rate case. The settlement agreement provides for a retail natural gas rate increase of $4.5 million, effective January 1, 2014. The rates reflect a 10.25% return on common equity and a common equity ratio of 48.62% in MGU's regulatory capital structure. Additionally, the order requires MGU to terminate its existing decoupling mechanism, effective December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminates MGU's existing uncollectible expense true-up mechanism after December 31, 2013.

MGU Depreciation Case

In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in the first quarter of 2013. In June 2013, the MPSC issued an order related to MGU's most recent depreciation case. This order also approved a settlement agreement reflecting recovery of these previously disallowed costs.

2014 UPPCO Rate Case

In June 2013, UPPCO filed an application with the MPSC to increase retail electric rates $7.9 million. Interim rates could be effective on January 1, 2014. UPPCO's request reflects a 10.75% return on common equity and a common equity ratio of 54.98% in its regulatory capital structure. The request was primarily driven by capital investments associated with FERC mandated replacements and upgrades of hydroelectric facilities, and increased costs associated with uncollectibles expense, line clearance, system losses, and general inflation. UPPCO is also requesting authority from the MPSC to implement a revenue adjustment mechanism that operates similar to a decoupling mechanism.

2012 UPPCO Rates

In December 2011, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $4.2 million, effective January 1, 2012. The new rates reflect a 10.20% return on common equity and a common equity ratio of 54.90% in its regulatory capital structure. The order stated that if UPPCO filed a rate case in 2013, the earliest effective date for new final rates or self-implemented rates would be January 1, 2014. Additionally, the order required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2013. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. It includes an annual 1.5% cap based on distribution revenues approved in the rate case. UPPCO had no decoupling mechanism in place during 2012.

In April 2012, the State of Michigan Court of Appeals ruled in a Detroit Edison proceeding that the MPSC did not have authority to approve electric decoupling mechanisms. This decision was not appealed. As a result of this ruling, UPPCO expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery. However, in August 2012, the MPSC issued an order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement. Therefore, in the third quarter of 2012, UPPCO reversed the $1.5 million previously expensed in the first quarter of 2012.

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Illinois

Qualifying Infrastructure Plant (QIP) Rider

In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives PGL a cost recovery mechanism for Illinois natural gas infrastructure upgrades that will be collected through a surcharge on customer bills. Later in July 2013, the ICC adopted emergency rules to implement the law. The ICC also opened a docket to develop permanent rules, which will replace the emergency rules. This Act eliminates a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation once PGL obtains an infrastructure tariff. In September 2013, PGL filed with the ICC requesting the proposed rider. The ICC must act no later than January 17, 2014. The ICC may modify the rider only to ensure compliance with the law. The rider would take effect on January 1 of the year in which the ICC issues its order.

2013 Rates

In June 2013, the ICC issued a final order authorizing a retail natural gas rate increase of $57.2 million for PGL and $6.6 million for NSG, effective June 27, 2013. The rates for PGL reflect a 9.28% return on common equity and a common equity ratio of 50.43% in its regulatory capital structure. The rates for NSG reflect a 9.28% return on common equity and a common equity ratio of 50.32% in its regulatory capital structure. The rate order also allows PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Appellate Court (Court).

In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG had asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors have requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. If the deferred tax asset created by the 2012 tax NOL is excluded from rate base or the corrections requested by PGL and NSG are not made, there is a potential that the federal income tax "normalization" rules could be violated. These rules specify that the benefit of claiming accelerated depreciation for federal income tax purposes cannot be given to customers before the tax cash flow is received by the company. Once received, the benefit must be given to customers over the useful life of the underlying property. A violation could cause PGL and NSG to lose the ability to claim accelerated depreciation deductions for income tax purposes. We believe this outcome is unlikely.

2012 Rates

In January 2012, the ICC issued a final order authorizing a retail natural gas rate increase of $57.8 million for PGL and $1.9 million for NSG, effective January 21, 2012. The rates for PGL reflected a 9.45% return on common equity and a common equity ratio of 49.00% in PGL's regulatory capital structure. The rates for NSG reflected a 9.45% return on common equity and a common equity ratio of 50.00% in NSG's regulatory capital structure. The rate order also approved a permanent decoupling mechanism.

The Illinois Attorney General and Citizens Utility Board appealed to the Court the ICC's authority to approve PGL's and NSG's decoupling mechanism and filed a motion to stay the implementation of the permanent decoupling mechanism or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanism subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG had established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanism. As a result, the reserves recorded in 2012 were reversed in the first quarter of 2013. PGL's and NSG's permanent decoupling mechanism is in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to appeal the Court's decision. The Illinois Supreme Court granted the request in September 2013. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse Illinois Supreme Court decision. Between April 1, 2013 and December 31, 2013, PGL and NSG expect to recover $14.8 million and $1.7 million, respectively, related to their 2012 decoupling mechanisms. As of September 30, 2013, PGL and NSG have recovered $6.4 million and $0.8 million, respectively, related to the 2012 decoupling mechanisms.

Minnesota

2014 Rate Case

In September 2013, MERC filed an application with the MPUC to increase retail natural gas distribution rates by $14.2 million. Interim rates could be effective on January 1, 2014. MERC's request reflects a 10.75% return on common equity and a common equity ratio of 50.31% in its regulatory capital structure. The request was primarily driven by general inflation, property taxes, improvements to customer service programs, efforts to expand the customer base which would have a positive rate effect in the future, and operating and maintenance projects to ensure reliability and safety for customers.

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2011 Rates

In July 2012, the MPUC approved a written order for MERC authorizing a retail natural gas rate increase of $11.0 million, effective January 1, 2013. The new rates reflect a 9.70% return on common equity and a common equity ratio of 50.48% in its regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

Federal

Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they would no longer receive due to this rate elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) be put into place. Load-serving entities paid these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006.

Integrys Energy Services initially expensed the majority of the total $19.2 million of billings paid during the transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC's SECA order and the transmission owners' FERC-ordered compliance filings. Integrys Energy Services protested the FERC’s SECA order, and through various rulings, ultimately received adverse decisions on most substantive issues. Integrys Energy Services appealed the adverse FERC decisions to the U.S. Court of Appeals for the D.C. Circuit.

In January 2013, Integrys Energy Services reached a settlement on all remaining issues with American Electric Power Service Corporation (AEP), the transmission owner affected the most from SECA payments collected from Integrys Energy Services. The parties filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC in January 2013. In July 2013, the FERC issued an order approving the uncontested Settlement Agreement. In September 2013, AEP made a lump sum payment of $9.5 million to Integrys Energy Services in complete settlement of the matters at issue (which included a $3.8 million receivable previously recorded). As a result, Integrys Energy Services recorded $5.7 million in other income, representing the portion of the $9.5 million settlement not previously recognized. In September 2013, Integrys Energy Services withdrew its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit, as discussed above.

NOTE 22 — SEGMENTS OF BUSINESS

At September 30, 2013, we reported five segments, which are described below.


•	The natural gas utility segment includes the regulated natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.


•	The electric utility segment includes the regulated electric utility operations of UPPCO and WPS.


•	The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.


•	Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas in deregulated markets. In addition, Integrys Energy Services invests in energy assets with renewable attributes.


•	The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.

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The tables below present information related to our reportable segments:



	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
September 30, 2013
External revenues	$	253.0		$	353.9		$	—	$	606.9		$	512.7		$	10.1		$	—		$	1,129.7
Intersegment revenues	4.2			0.1			—		4.3			0.3			0.3			(4.9		)	—
Depreciation and amortization expense	35.6			25.7			—		61.3			2.9			5.5			(0.1		)	69.6
Earnings from equity method investments	—			—			22.3		22.3			0.5			0.3			—			23.1
Miscellaneous income	0.4			2.8			—		3.2			6.2			5.7			(3.0		)	12.1
Interest expense	12.7			8.8			—		21.5			0.5			14.1			(3.0		)	33.1
Provision (benefit) for income taxes	(19.5		)	25.1			8.6		14.2			6.6			(2.8		)	—			18.0
Net income (loss) from continuing operations	(19.5		)	40.9			13.7		35.1			12.3			(8.0		)	—			39.4
Discontinued operations	—			—			—		—			(0.6		)	—			—			(0.6		)
Preferred stock dividends of subsidiary	(0.1		)	(0.6		)	—		(0.7		)	—			—			—			(0.7		)
Net income (loss) attributed to common shareholders	(19.6		)	40.3			13.7		34.4			11.7			(8.0		)	—			38.1



	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
September 30, 2012
External revenues	$	215.5		$	366.8		$	—	$	582.3		$	335.5		$	9.9		$	—		$	927.7
Intersegment revenues	4.5			—			—		4.5			0.1			0.3			(4.9		)	—
Depreciation and amortization expense	33.2			22.3			—		55.5			2.7			4.8			(0.1		)	62.9
Earnings from equity method investments	—			—			21.7		21.7			0.5			—			—			22.2
Miscellaneous income	0.1			0.9			—		1.0			0.3			5.7			(3.9		)	3.1
Interest expense	11.7			8.9			—		20.6			0.5			12.7			(3.9		)	29.9
Provision (benefit) for income taxes	(11.5		)	19.5			8.3		16.3			16.1			(2.8		)	—			29.6
Net income (loss) from continuing operations	(13.9		)	47.8			13.4		47.3			32.2			(5.2		)	—			74.3
Discontinued operations	—			—			—		—			(8.0		)	—			—			(8.0		)
Preferred stock dividends of subsidiary	(0.1		)	(0.6		)	—		(0.7		)	—			—			—			(0.7		)
Noncontrolling interest in subsidiaries	—			—			—		—			—			0.1			—			0.1
Net income (loss) attributed to common shareholders	(14.0		)	47.2			13.4		46.6			24.2			(5.1		)	—			65.7

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	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Nine Months Ended
September 30, 2013
External revenues	$	1,412.4		$	1,012.7		$	—	$	2,425.1		$	1,470.7		$	28.1		$	—		$	3,923.9
Intersegment revenues	8.6			0.1			—		8.7			0.9			1.0			(10.6		)	—
Depreciation and amortization expense	100.1			73.0			—		173.1			8.4			14.9			(0.4		)	196.0
Earnings from equity method investments	—			—			66.0		66.0			1.2			1.0			—			68.2
Miscellaneous income	0.8			6.6			—		7.4			8.0			18.0			(10.1		)	23.3
Interest expense	37.3			26.4			—		63.7			1.5			35.9			(10.1		)	91.0
Provision (benefit) for income taxes	43.1			56.9			25.3		125.3			11.7			(12.7		)	—			124.3
Net income (loss) from continuing operations	72.0			94.5			40.7		207.2			22.5			(12.0		)	—			217.7
Discontinued operations	—			—			—		—			(1.2		)	5.9			—			4.7
Preferred stock dividends of subsidiary	(0.4		)	(1.9		)	—		(2.3		)	—			—			—			(2.3		)
Noncontrolling interest in subsidiaries	—			—			—		—			—			0.1			—			0.1
Net income (loss) attributed to common shareholders	71.6			92.6			40.7		204.9			21.3			(6.0		)	—			220.2



	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Nine Months Ended
September 30, 2012
External revenues	$	1,131.3		$	985.6		$	—	$	2,116.9		$	873.7		$	24.6		$	—		$	3,015.2
Intersegment revenues	8.1			—			—		8.1			0.6			1.5			(10.2		)	—
Depreciation and amortization expense	98.3			66.4			—		164.7			7.4			15.9			(0.4		)	187.6
Earnings from equity method investments	—			—			63.8		63.8			1.2			0.5			—			65.5
Miscellaneous income	0.6			1.5			—		2.1			0.8			16.4			(12.1		)	7.2
Interest expense	35.1			27.1			—		62.2			1.5			38.4			(12.1		)	90.0
Provision (benefit) for income taxes	32.6			42.4			24.0		99.0			23.6			(16.0		)	—			106.6
Net income (loss) from continuing operations	53.8			94.3			39.8		187.9			46.0			(9.1		)	—			224.8
Discontinued operations	—			—			—		—			(11.0		)	1.8			—			(9.2		)
Preferred stock dividends of subsidiary	(0.4		)	(1.9		)	—		(2.3		)	—			—			—			(2.3		)
Noncontrolling interest in subsidiaries	—			—			—		—			—			0.1			—			0.1
Net income (loss) attributed to common shareholders	53.4			92.4			39.8		185.6			35.0			(7.2		)	—			213.4

NOTE 23 — NEW ACCOUNTING PRONOUNCEMENTS

Recently Issued Accounting Guidance Not Yet Effective

Accounting Standards Update (ASU) 2013-04, "Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date," was issued in February 2013. The guidance requires an entity to measure obligations under these arrangements, for which the total amount of the obligation is fixed at the reporting date, as the sum of the reporting entity's portion and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires additional disclosures about the nature and amount of the obligations. The guidance is effective for reporting periods beginning after December 15, 2013. Adoption of this guidance is not expected to have a significant impact on our financial statements.

ASU 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists," was issued in July 2013. The guidance states that an unrecognized tax benefit should be presented in the financial statements

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as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. There are certain exceptions, however, under which the unrecognized tax benefit would be presented in the balance sheet as a liability. The guidance is effective for reporting periods beginning after December 15, 2013. Adoption of this guidance is not expected to have a significant impact on our financial statements.

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

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2012.

SUMMARY

We are a diversified energy holding company with regulated natural gas and electric utility operations (serving customers in Illinois, Michigan, Minnesota, and Wisconsin), an approximate 34% equity ownership interest in ATC (a federally regulated electric transmission company), and nonregulated energy operations.

RESULTS OF OPERATIONS

Earnings Summary



	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30						Change in 2013 Over 2012
(Millions, except per share amounts)	2013			2012			Change in 2013 Over 2012		2013			2012			Change in 2013 Over 2012
Natural gas utility operations	$	(19.6	)	$	(14.0	)	40.0	%	$	71.6		$	53.4		34.1	%
Electric utility operations	40.3			47.2			(14.6	)%	92.6			92.4			0.2	%
Electric transmission investment	13.7			13.4			2.2	%	40.7			39.8			2.3	%
Integrys Energy Services’ operations	11.7			24.2			(51.7	)%	21.3			35.0			(39.1	)%
Holding company and other operations	(8.0		)	(5.1		)	56.9	%	(6.0		)	(7.2		)	(16.7	)%

Net income (loss) attributed to common shareholders	$	38.1		$	65.7		(42.0	)%	$	220.2		$	213.4		3.2	%

Basic earnings per share	$	0.48		$	0.84		(42.9	)%	$	2.78		$	2.72		2.2	%
Diluted earnings per share	$	0.47		$	0.83		(43.4	)%	$	2.76		$	2.69		2.6	%

Average shares of common stock
Basic	79.8			78.5			1.7	%	79.3			78.5			1.0	%
Diluted	80.2			79.3			1.1	%	79.9			79.3			0.8	%

Third Quarter 2013 Compared with Third Quarter 2012

The $27.6 million decrease in our earnings was driven by:


•	A $13.5 million after-tax non-cash decrease in Integrys Energy Services’ margins related to derivative and inventory fair value adjustments.


•	A $6.8 million after-tax decrease in Integrys Energy Services' realized retail electric margins.


•	The $5.9 million quarter-over-quarter negative impact of the reversal in 2012 of deferred income taxes at WPS that had been expensed in prior years due to the implementation of federal health care reform. WPS was authorized recovery of this amount in its 2013 rate case settlement.


•	A $5.8 million after-tax increase in natural gas distribution costs at the natural gas utilities.

These decreases were partially offset by a $7.4 million increase in income from discontinued operations. See Note 5, "Discontinued Operations," for more information.

Nine Months 2013 Compared with Nine Months 2012

The $6.8 million increase in our earnings was driven by:


•	A $21.2 million after-tax increase in natural gas utility margins in 2013 due to lower sales volumes in 2012, combined with the absence of decoupling at PGL, NSG, and MERC in 2012.


•	A $13.9 million increase in income from discontinued operations. See Note 5, "Discontinued Operations," for more information.


•	A $9.9 million after-tax increase in natural gas utility margins due to the first quarter 2013 reversal of reserves recorded in 2012 against decoupling accruals at PGL and NSG. In March 2013, the Illinois Appellate Court affirmed the ICC's authority to approve the permanent decoupling mechanisms. See Note 21, "Regulatory Environment," for more information.

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•	The $9.5 million after-tax positive impact of rate orders at the natural gas utilities.

These increases were partially offset by:


•	A $17.3 million after-tax increase in operating expenses at the natural gas utilities, excluding items directly offset in margins, driven by an increase in natural gas distribution costs.


•	A $16.0 million after-tax non-cash decrease in Integrys Energy Services’ margins related to derivative and inventory fair value adjustments.


•	An $8.3 million after-tax increase in operating expenses at Integrys Energy Services, driven by an increase in sales and marketing costs and outside service fees, primarily related to the expansion of the residential and small commercial customer segment.


•	The $5.9 million period-over-period negative impact of the reversal in 2012 of deferred income taxes at WPS that had been expensed in prior years due to the implementation of federal health care reform. WPS was authorized recovery of this amount in its 2013 rate case settlement.

Regulated Natural Gas Utility Segment Operations



	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30						Change in 2013 Over 2012
(Millions, except heating degree days)	2013			2012			Change in 2013 Over 2012		2013			2012			Change in 2013 Over 2012
Revenues	$	257.2		$	220.0		16.9	%	$	1,421.0		$	1,139.4		24.7	%
Purchased natural gas costs	93.8			71.9			30.5	%	685.4			511.1			34.1	%
Margins	163.4			148.1			10.3	%	735.6			628.3			17.1	%

Operating and maintenance expense	144.9			119.7			21.1	%	454.9			382.0			19.1	%
Depreciation and amortization expense	35.6			33.2			7.2	%	100.1			98.3			1.8	%
Taxes other than income taxes	9.6			9.0			6.7	%	29.0			27.1			7.0	%
Operating income (loss)	(26.7		)	(13.8		)	93.5	%	151.6			120.9			25.4	%

Miscellaneous income	0.4			0.1			300.0	%	0.8			0.6			33.3	%
Interest expense	12.7			11.7			8.5	%	37.3			35.1			6.3	%
Other expense	(12.3		)	(11.6		)	6.0	%	(36.5		)	(34.5		)	5.8	%

Income (loss) before taxes	$	(39.0	)	$	(25.4	)	53.5	%	$	115.1		$	86.4		33.2	%

Retail throughput in therms
Residential	89.2			87.2			2.3	%	1,108.1			864.6			28.2	%
Commercial and industrial	43.2			36.3			19.0	%	358.9			270.7			32.6	%
Other	14.6			23.3			(37.3	)%	45.4			56.2			(19.2	)%
Total retail throughput in therms	147.0			146.8			0.1	%	1,512.4			1,191.5			26.9	%

Transport throughput in therms
Residential	16.4			15.8			3.8	%	166.8			134.2			24.3	%
Commercial and industrial	291.0			299.7			(2.9	)%	1,182.7			1,110.7			6.5	%
Total transport throughput in therms	307.4			315.5			(2.6	)%	1,349.5			1,244.9			8.4	%

Total throughput in therms	454.4			462.3			(1.7	)%	2,861.9			2,436.4			17.5	%

Weather
Average heating degree days	140			165			(15.2	)%	4,589			3,367			36.3	%

Natural gas utility margins are defined as natural gas utility operating revenues less purchased natural gas costs. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since prudently incurred natural gas commodity costs are passed through to our customers in current rates. There was an approximate 32% and 6% increase in the average per-unit cost of natural gas sold during the three and nine month periods ended September 30, 2013, respectively, which had no impact on margins.

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Third Quarter 2013 Compared with Third Quarter 2012

Margins

Regulated natural gas utility segment margins increased $15.3 million, driven by:


•	An approximate $11 million net increase in margins due to rate orders. See Note 21, "Regulatory Environment," for more information.


◦	The rate increases at PGL and NSG, effective June 27, 2013, and other impacts of rate design, had an approximate $9 million positive impact on margins.

◦

The approximate $2 million increase in margins at WPS was driven by the quarter-over-quarter positive impact from the straight-line amortization of prior year decoupling deferrals, partially offset by a decrease in rates, both of which were approved in their rate order, effective January 1, 2013. The impact of the decrease in rates is not recognized evenly throughout the year, as recognition is based on volumes sold, which are generally lower in the third quarter.


•	An approximate $5 million net increase in margins related to certain riders at PGL and NSG and certain energy efficiency programs at four of our natural gas utilities. This increase was offset by an equal increase in operating expenses, resulting in no impact on earnings.


◦	Our natural gas utilities billed approximately $3 million more to customers for certain energy efficiency programs in 2013.


◦	PGL and NSG recovered approximately $2 million more for environmental cleanup costs at their former manufactured gas plant sites related to an increase in remediation activity during 2013. See Note 12, "Commitments and Contingencies," for more information about the manufactured gas plant sites.

Operating Loss

The operating loss at the regulated natural gas utility segment increased $12.9 million. This increase was driven by a $28.2 million increase in operating expenses, partially offset by the $15.3 million increase in margins discussed above.

The increase in operating expenses was primarily due to:

•

A $9.7 million increase in natural gas distribution costs, primarily at PGL. The increase was partially due to increased labor and contractor costs driven by additional compliance work. A portion of the compliance work was driven by new local regulations related to natural gas distribution main openings and repairs in the public way. Natural gas distribution costs also increased due to a plastic pipe fittings replacement project.


•	A $3.0 million increase in energy efficiency program expenses at certain natural gas utilities. For the majority of these expenses, margins increased by an equal amount, resulting in no impact on earnings.

•

A $2.9 million increase in bad debt expense driven by a cost of natural gas component included as part of PGL's and NSG's bad debt expense tracking mechanisms. This natural gas component is charged to customers based on actual volumes and natural gas prices. As a result of this component, bad debt expense was primarily impacted by higher natural gas costs in the third quarter of 2013. However, the increase in bad debt expense does not impact earnings as it is offset by higher rates, resulting in higher margins.


•	A $2.8 million increase driven by higher amortization of regulatory assets at certain of our natural gas utilities related to environmental cleanup costs for manufactured gas plant sites. For the majority of these expenses, margins increased by an equal amount, resulting in no impact on earnings.


•	A $2.4 million increase in depreciation and amortization expense. This increase is a result of continued investment in property and equipment, primarily driven by the AMRP at PGL.


•	A $2.1 million increase in legal and outside service expense.

•

A $1.3 million net increase in employee benefit costs. The employee benefit costs increase of $1.8 million was partially due to higher pension expense, primarily at PGL, driven by a lower discount rate in 2013. The lower discount rate did not significantly impact the other natural gas utilities due to an increase in contributions to those plans in prior years, which increased plan assets. Amortization of negative investment returns from prior years also increased pension expense in the third quarter of 2013. WPS has deferred $0.5 million of certain increases in pension and other employee benefit costs that will be recovered in a future rate proceeding as a result of its 2013 rate order. See Note 21, "Regulatory Environment," for more information.


•	A $1.1 million increase in asset usage charges from IBS, driven by new software for both natural gas management and work asset management that was placed into service during the third quarter of 2013.

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Nine Months 2013 Compared with Nine Months 2012

Margins

Regulated natural gas utility segment margins increased $107.3 million, driven by:


•	An approximate $52 million net increase in margins due to sales volume variances and our decoupling mechanisms.

◦

In 2012, margins were lower by approximately $35 million primarily due to unusually warm weather. At the same time, decoupling accruals at PGL and NSG were offset by reserves, and MERC did not have decoupling. Therefore, in 2012, margins for PGL, NSG, and MERC were more sensitive to volume variances. See Note 21, "Regulatory Environment," for more information. In addition, decoupling across the natural gas utilities does not cover all jurisdictions or customer classes.

◦

In 2013, PGL and NSG recorded an increase in revenues of approximately $17 million when reserves established against regulatory assets related to decoupling from a prior period were reversed. The reversal was recorded after the Illinois Appellate Court issued an opinion in March 2013 that affirmed the ICC's order approving the decoupling mechanisms. See Note 21, "Regulatory Environment," for more information.


•	An approximate $40 million increase in margins related to certain riders at PGL and NSG and certain energy efficiency programs at four of our natural gas utilities. This increase was offset by an equal increase in operating expenses, resulting in no impact on earnings.


◦	PGL and NSG recovered approximately $21 million more for environmental cleanup costs at their former manufactured gas plant sites related to an increase in remediation activity during 2013. See Note 12, "Commitments and Contingencies," for more information about the manufactured gas plant sites.


◦	Our natural gas utilities billed approximately $19 million more to customers for certain energy efficiency programs in 2013.


•	An approximate $16 million net increase in margins due to rate orders. See Note 21, "Regulatory Environment," for more information.


◦	The rate increases at PGL and NSG, effective June 27, 2013, and January 21, 2012, and other impacts of rate design, had an approximate $15 million positive impact on margins.


◦	MERC had an approximate $2 million increase in margins primarily driven by the impact of a July 2012 rate order from the MPUC. Customer refunds were accrued in 2012 as a result of 2011 interim rates that had been in effect.


◦	A reduction in rates at WPS, effective January 1, 2013, resulted in an approximate $1 million negative impact on margins.

Operating Income

Operating income at the regulated natural gas utility segment increased $30.7 million. This increase was driven by the $107.3 million increase in margins discussed above, partially offset by a $76.6 million increase in operating expenses.

The increase in operating expenses was primarily due to:


•	A $22.5 million increase in energy efficiency program expenses at certain natural gas utilities. For the majority of these expenses, margins increased by an equal amount, resulting in no impact on earnings.


•	A $22.3 million increase driven by higher amortization of regulatory assets at certain of our natural gas utilities related to environmental cleanup costs for manufactured gas plant sites. For the majority of these expenses, margins increased by an equal amount, resulting in no impact on earnings.

•

A $14.1 million increase in natural gas distribution costs, primarily at PGL. The increase was partially due to increased labor and contractor costs driven by additional compliance work. A portion of the compliance work was driven by new local regulations related to natural gas distribution main openings and repairs in the public way. Natural gas distribution costs also increased due to a plastic pipe fittings replacement project.

•

A $7.1 million net increase in employee benefit costs. The employee benefit costs increase of $8.7 million was partially due to higher pension expense, primarily at PGL, driven by a lower discount rate in 2013. The lower discount rate did not significantly impact the other natural gas utilities due to an increase in contributions to those plans in prior years, which increased plan assets. Amortization of negative investment returns from prior years also increased pension expense in 2013. WPS has deferred $1.6 million of certain increases in pension and other

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employee benefit costs that will be recovered in a future rate proceeding as a result of its 2013 rate order. See Note 21, "Regulatory Environment," for more information.

•

A $3.3 million increase in bad debt expense, driven by a cost of natural gas component included as part of PGL's and NSG's bad debt expense tracking mechanisms. This natural gas component is charged to customers based on actual volumes and natural gas prices. As a result of this component, bad debt expense was primarily impacted by higher natural gas costs in 2013, and, to a lesser extent, by the increase in sales volumes. However, the increase in bad debt expense does not impact earnings as it is offset by higher rates, resulting in higher margins.


•	A $3.2 million increase in legal and outside service expense.

•

A $1.8 million net increase in depreciation and amortization expense. The increase is a result of continued investment in property and equipment, primarily driven by the AMRP at PGL. The increase was partially offset by a $3.4 million reduction in expense at MERC related to a new depreciation study approved by the MPUC on July 29, 2013, retroactive to January 1, 2012. The study included changes to salvage values and costs of removal, as well as extensions to the service lives of certain assets. In addition, there was a $2.5 million reduction in expense at MGU. In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's previously ordered disallowance associated with the early retirement of certain MGU assets in 2010. See Note 21, "Regulatory Environment," for more information.

The increase in operating expenses was partially offset by a $2.9 million decrease in workers compensation expense related to both fewer incidents and less severe injuries during 2013, primarily at PGL.

Other Expense

Other expense at the regulated natural gas utilities increased $2.0 million in 2013. Interest expense on long-term debt increased, driven by higher average long-term debt outstanding in 2013.

Regulated Electric Utility Segment Operations



	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30						Change in 2013 Over 2012
(Millions, except degree days)	2013			2012			Change in 2013 Over 2012		2013			2012			Change in 2013 Over 2012
Revenues	$	354.0		$	366.8		(3.5	)%	$	1,012.8		$	985.6		2.8	%
Fuel and purchased power costs	133.6			160.9			(17.0	)%	408.1			423.9			(3.7	)%
Margins	220.4			205.9			7.0	%	604.7			561.7			7.7	%

Operating and maintenance expense	110.6			96.6			14.5	%	323.5			296.7			9.0	%
Depreciation and amortization expense	25.7			22.3			15.2	%	73.0			66.4			9.9	%
Taxes other than income taxes	12.1			11.7			3.4	%	37.0			36.3			1.9	%
Operating income	72.0			75.3			(4.4	)%	171.2			162.3			5.5	%

Miscellaneous income	2.8			0.9			211.1	%	6.6			1.5			340.0	%
Interest expense	8.8			8.9			(1.1	)%	26.4			27.1			(2.6	)%
Other expense	(6.0		)	(8.0		)	(25.0	)%	(19.8		)	(25.6		)	(22.7	)%

Income before taxes	$	66.0		$	67.3		(1.9	)%	$	151.4		$	136.7		10.8	%

Sales in kilowatt-hours
Residential	837.8			897.2			(6.6	)%	2,354.2			2,359.8			(0.2	)%
Commercial and industrial	2,242.8			2,275.4			(1.4	)%	6,418.5			6,500.4			(1.3	)%
Wholesale	1,092.4			1,461.8			(25.3	)%	3,277.1			3,503.6			(6.5	)%
Other	8.0			8.3			(3.6	)%	26.4			26.8			(1.5	)%
Total sales in kilowatt-hours	4,181.0			4,642.7			(9.9	)%	12,076.2			12,390.6			(2.5	)%

Weather
WPS:
Heating degree days	216			252			(14.3	)%	5,126			3,864			32.7	%
Cooling degree days	396			514			(23.0	)%	527			789			(33.2	)%

UPPCO:
Heating degree days	473			434			9.0	%	6,189			4,898			26.4	%
Cooling degree days	194			236			(17.8	)%	230			335			(31.3	)%

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Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.

Third Quarter 2013 Compared with Third Quarter 2012

Margins

Regulated electric utility segment margins increased $14.5 million, driven by:

•

An approximate $13 million increase in margins from WPS's fuel and purchased power costs that are not included in its fuel and purchased power cost recovery mechanism. The increase was primarily due to a decline in purchased power costs as a result of the acquisition of Fox Energy Company LLC, which had no impact on net income. The net difference between the purchased power costs and the costs of owning the plant are deferred for recovery or refund in a future rate case (the net difference is reflected in operating expenses below).


•	An approximate $4 million increase in margins due to a retail electric rate increase at WPS, effective January 1, 2013. For more information on the 2013 PSCW rate order, see Note 21, "Regulatory Environment."

These increases were partially offset by:


•	A $1.5 million decrease in margins due to the quarter-over-quarter impact of the 2012 reversal of the write-off of UPPCO's net regulatory asset related to its 2010 and 2011 decoupling deferrals. The write-off was initially recorded in the first quarter of 2012.

•

An approximate $1 million net decrease in margins from residential and commercial and industrial customers due to variances related to sales volumes, including the impact of decoupling. The quarter-over-quarter impact of decoupling does not directly correlate with the quarter-over-quarter impact of the change in sales volumes, as WPS's decoupling mechanism was changed in 2013, and UPPCO did not have decoupling in 2012. See Note 21, "Regulatory Environment," for more information.

Operating Income

Operating income at the regulated electric utility segment decreased $3.3 million. The decrease was driven by a $17.8 million increase in operating expenses, partially offset by the $14.5 million increase in margins discussed above. The increase in operating expenses was driven by:


•	A $7.9 million increase in maintenance expense due to a greater number of planned outages for certain WPS generation plants in 2013, driven primarily by an outage at Weston 3. Also included in this amount is maintenance expense associated with the recently acquired Fox Energy Center.


•	A $3.4 million increase in depreciation and amortization expense mainly due to the acquisition of the Fox Energy Center, partially offset by a reduction in the depreciable basis of WPS's Crane Creek Wind Project. The reduction is the result of WPS's election to claim a Section 1603 Grant for the project in lieu of production tax credits.


•	A $2.5 million increase in electric transmission expense.

•

A $1.5 million increase due to WPS's deferral of the net difference between actual and rate case-approved costs resulting from the purchase of Fox Energy Company LLC. The 2013 PSCW rate order did not reflect this purchase or the related termination of the power purchase agreement. However, WPS did receive approval from the PSCW to defer ownership costs above or below its power purchase agreement expenses for recovery or refund in a future rate case.


•	A $1.0 million increase in various other costs associated with the acquisition and operation of the Fox Energy Center.

Other Expense

Other expense decreased $2.0 million, driven by an increase in AFUDC due to environmental compliance projects at the Columbia plant.

Nine Months 2013 Compared with Nine Months 2012

Margins

Regulated electric utility segment margins increased $43.0 million, driven by:


•	An approximate $21 million increase in margins from WPS's fuel and purchased power costs that are not included in its fuel and purchased power cost recovery mechanism. The increase was primarily due to a decline in purchased power costs as a result of the acquisition of Fox

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Energy Company LLC, which had no impact on net income. The net difference between the purchased power costs and the costs of owning the plant are deferred for recovery or refund in a future rate case (the net difference is reflected in operating expenses below).


•	An approximate $13 million increase in margins due to a retail electric rate increase at WPS, effective January 1, 2013. For more information on the 2013 PSCW rate order, see Note 21, "Regulatory Environment."

•

An approximate $7 million net increase in margins from residential and commercial and industrial customers due to variances related to sales volumes, including the impact of decoupling. The period-over-period impact of decoupling does not directly correlate with the period-over-period impact of the change in sales volumes, as WPS's decoupling mechanism was changed in 2013, and UPPCO did not have decoupling in 2012. See Note 21, "Regulatory Environment," for more information.

Operating Income

Operating income at the regulated electric utility segment increased $8.9 million. The increase was driven by the $43.0 million increase in margins discussed above, partially offset by a $34.1 million increase in operating expenses. The increase in operating expenses was driven by:


•	A $9.0 million increase in maintenance expense due to a greater number of planned outages for certain WPS generation plants in 2013, driven primarily by an outage at Weston 3. Also included in this amount is maintenance expense associated with the recently acquired Fox Energy Center.


•	A $7.3 million increase in electric transmission expense.


•	A $6.6 million increase in depreciation and amortization expense mainly due to the acquisition of the Fox Energy Center, partially offset by a reduction in the depreciable basis of WPS's Crane Creek Wind Project. The reduction was the result of WPS's election to claim a Section 1603 Grant for the project in lieu of production tax credits.

•

A $4.3 million increase due to WPS's deferral of the net difference between actual and rate case-approved costs resulting from the purchase of Fox Energy Company LLC. The 2013 PSCW rate order did not reflect this purchase or the related termination of the power purchase agreement. However, WPS did receive approval from the PSCW to defer ownership costs above or below its power purchase agreement expenses for recovery or refund in a future rate case.


•	A $3.6 million increase in various costs associated with the acquisition and operation of the Fox Energy Center.


•	A $2.5 million increase in WPS's customer assistance expense, driven by the period-over-period change in the amortization of amounts recoverable from or refundable to customers related to energy efficiency.

In addition, a $3.8 million increase in employee benefit related expenses was more than offset by the $5.4 million positive impact of the deferral of certain components of pension and other employee benefit costs that will be recovered in a future rate proceeding as a result of the WPS 2013 PSCW rate order. The increase in employee benefit related expenses was driven by the amortization of negative investment returns from prior years, which increased both the pension and other postretirement benefit expenses.

Other Expense

Other expense decreased $5.8 million, driven by an increase in AFUDC due to environmental compliance projects at the Columbia plant.

Electric Transmission Investment Segment Operations



	Three Months Ended September 30				Change in 2013 Over 2012		Nine Months Ended September 30				Change in 2013 Over 2012
(Millions)	2013		2012		Change in 2013 Over 2012		2013		2012		Change in 2013 Over 2012
Earnings from equity method investments	$	22.3	$	21.7	2.8	%	$	66.0	$	63.8	3.4	%

Third Quarter 2013 Compared with Third Quarter 2012

Earnings from Equity Method Investments

Earnings from equity method investments at the electric transmission investment segment increased $0.6 million. The increase resulted from higher earnings related to our approximate 34% ownership interest in ATC. Our income increases as ATC continues to increase its rate base by investing in transmission equipment and facilities for improved reliability and economic benefits for customers.

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Nine Months 2013 Compared with Nine Months 2012

Earnings from Equity Method Investments

Earnings from equity method investments at the electric transmission investment segment increased $2.2 million. The increase resulted from higher earnings related to our approximate 34% ownership interest in ATC. Our income increases as ATC continues to increase its rate base by investing in transmission equipment and facilities for improved reliability and economic benefits for customers.

Integrys Energy Services Nonregulated Segment Operations

Integrys Energy Services has been able to take advantage of continued growth opportunities as evidenced by increasing volumes delivered and contracted for future delivery in certain markets. During the nine months ended September 30, 2013, delivered electric and natural gas volumes grew approximately 54% and 53%, respectively, compared with the same period in 2012. In addition, Integrys Energy Services' electric and natural gas volumes for future delivery grew by approximately 39% and 109%, respectively, from September 30, 2012 to September 30, 2013. However, sustained low commodity prices, capital costs, and market volatility have led to continued competitive pressure on per-unit margins.



	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30					Change in 2013 Over 2012
(Millions, except natural gas sales volumes)	2013			2012			Change in 2013 Over 2012		2013		2012			Change in 2013 Over 2012
Revenues	$	513.0		$	335.6		52.9	%	$	1,471.6	$	874.3		68.3	%
Cost of sales	469.3			258.8			81.3	%	1,343.7		717.7			87.2	%
Margins	43.7			76.8			(43.1	)%	127.9		156.6			(18.3	)%
Margin Detail
Realized retail electric margins	15.9			27.2			(41.5	)%	66.4		66.4			—	%
Realized wholesale electric margins ⁽¹⁾	—			0.1			(100.0	)%	0.4		(0.4		)	N/A
Realized renewable energy asset margins	5.0			4.3			16.3	%	12.5		11.3			10.6	%
Fair value accounting adjustments	17.4			40.9			(57.5	)%	15.4		39.1			(60.6	)%
Electric and renewable energy asset margins	38.3			72.5			(47.2	)%	94.7		116.4			(18.6	)%
Realized retail natural gas margins ⁽²⁾	4.4			4.2			4.8	%	27.9		33.6			(17.0	)%
Realized wholesale natural gas margins⁽¹⁾	0.1			0.2			(50.0	)%	0.2		(1.4		)	N/A
Lower-of-cost-or-market inventory adjustments	(0.9		)	1.3			N/A		1.4		4.6			(69.6	)%
Fair value accounting adjustments	1.8			(1.4		)	N/A		3.7		3.4			8.8	%
Natural gas margins	5.4			4.3			25.6	%	33.2		40.2			(17.4	)%

Operating and maintenance expense	27.5			25.5			7.8	%	90.4		77.9			16.0	%
Depreciation and amortization expense	2.9			2.7			7.4	%	8.4		7.4			13.5	%
Taxes other than income taxes	0.6			0.6			—	%	2.6		2.2			18.2	%
Operating income	12.7			48.0			(73.5	)%	26.5		69.1			(61.6	)%

Earnings from equity method investments	0.5			0.5			—	%	1.2		1.2			—	%
Miscellaneous income	6.2			0.3			1,966.7	%	8.0		0.8			900.0	%
Interest expense	0.5			0.5			—	%	1.5		1.5			—	%
Other income	6.2			0.3			1,966.7	%	7.7		0.5			1,440.0	%

Income before taxes	$	18.9		$	48.3		(60.9	)%	$	34.2	$	69.6		(50.9	)%

Physically settled volumes
Retail electric sales volumes in kwh	6,291.0			4,010.6			56.9	%	15,447.3		10,012.2			54.3	%
Wholesale assets and distributed solar electric sales volumes in kwh⁽³⁾	17.4			26.3			(33.8	)%	51.1		72.9			(29.9	)%
Retail natural gas sales volumes in bcf	34.8			19.3			80.3	%	122.6		80.3			52.7	%

kwh — kilowatt-hours

bcf — billion cubic feet


⁽¹⁾	Realized wholesale activity relates to remaining contracts for which offsetting positions were entered into.


⁽²⁾	These amounts include negative margin of $1.5 million and $2.8 million for the three and nine months ended September 30, 2013, respectively, related to the amortization of the net amount paid for customer and related supply contracts in connection with the acquisition of Compass Energy Services. See Note 4, "Acquisitions," for more information regarding this purchase.


⁽³⁾	The volumes related to the remaining wholesale electric contracts are not significant.

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Third Quarter 2013 Compared with Third Quarter 2012

Revenues

Integrys Energy Services’ revenues increased $177.4 million, primarily driven by higher retail sales volumes.

Margins

Integrys Energy Services’ margins decreased $33.1 million. Significant items contributing to the change in margins were as follows:

Electric and Renewable Energy Asset Margins

Realized retail electric margins

Realized retail electric margins decreased $11.3 million. The decrease was primarily driven by continued competitive pressure on per-unit margins related to commercial and industrial customers. In addition, there were margin timing impacts as prices for certain customer contracts are fixed per unit over the term of the contract, while the associated costs can vary month to month over the same period. Integrys Energy Services was also unable to fully recover fixed costs related to its electric aggregation customers as usage for these customers was lower than anticipated. These decreases were partially offset by higher sales volumes.

Realized renewable energy asset margins

Realized renewable energy asset margins increased $0.7 million. The increase was primarily driven by continued investment in solar energy projects.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $23.5 million decrease in electric margins quarter over quarter. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply associated with electric sales contracts. These adjustments will reverse in future periods as contracts settle.

Natural Gas Margins

Realized retail natural gas margins

Realized retail natural gas margins, which include the amortization of customer and supply contracts related to the acquisition of Compass Energy Services, increased $0.2 million. The increase was primarily driven by higher sales volumes. Fewer opportunities to take advantage of natural gas price volatility and changes in market prices for natural gas storage and transportation capacity in the third quarter of 2013 as well as continued competitive pressure on per-unit margins partially offset the increase.

Inventory accounting adjustments

Integrys Energy Services’ physical natural gas inventory is valued at the lower of cost or market. When the market price of natural gas is lower than the carrying value of the inventory, write-downs are recorded within margins to reflect inventory at the end of the period at its net realizable value. These write-downs result in higher margins in future periods as the inventory that was written down is sold. The $2.2 million quarter-over-quarter decrease in margins from inventory adjustments was driven by an increase in write-downs.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $3.2 million increase in natural gas margins quarter over quarter. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply, storage, and transportation associated with natural gas sales contracts. These adjustments will reverse in future periods as contracts settle.

Operating Income

Integrys Energy Services’ operating income decreased $35.3 million. The main driver of the decrease was the $33.1 million decrease in margins discussed above. In addition, operating expenses increased $2.2 million, driven by a $1.8 million increase in payroll and employee benefit expenses, primarily related to the addition of employees as a result of the Compass Energy Services acquisition. See Note 4, "Acquisitions," for more information.

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Other Income

Integrys Energy Services’ other income increased $5.9 million. The main driver of the increase was the recognition of an additional $5.7 million related to the Seams Elimination Charge Adjustment (SECA) settlement received in the third quarter of 2013. See Note 21, "Regulatory Environment," for more information.

Nine Months 2013 Compared with Nine Months 2012

Revenues

Integrys Energy Services’ revenues increased $597.3 million, primarily driven by higher retail sales volumes.

Margins

Integrys Energy Services’ margins decreased $28.7 million. Significant items contributing to the change in margins were as follows:

Electric and Renewable Energy Asset Margins

Realized retail electric margins

There was no material change in realized retail electric margins. Higher sales volumes in 2013 were partially offset by continued competitive pressure on per-unit margins. In addition, Integrys Energy Services was unable to fully recover fixed costs related to its electric aggregation customers as usage for these customers was lower than anticipated.

Realized renewable energy asset margins

Realized renewable energy asset margins increased $1.2 million. The increase was primarily driven by continued investment in solar energy projects.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $23.7 million decrease in electric margins period over period. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply associated with electric sales contracts. These adjustments will reverse in future periods as contracts settle.

Natural Gas Margins

Realized retail natural gas margins

Realized retail natural gas margins, which include the amortization of customer and supply contracts related to the acquisition of Compass Energy Services, decreased $5.7 million. The decrease was primarily driven by fewer opportunities to take advantage of natural gas price volatility and changes in market prices for natural gas storage and transportation capacity in 2013 as well as continued competitive pressure on per-unit margins. These decreases were partially offset by higher sales volumes.

Inventory accounting adjustments

Integrys Energy Services’ physical natural gas inventory is valued at the lower of cost or market. When the market price of natural gas is lower than the carrying value of the inventory, write-downs are recorded within margins to reflect inventory at the end of the period at its net realizable value. These write-downs result in higher margins in future periods as the inventory that was written down is sold. The $3.2 million period-over-period decrease in margins from inventory adjustments was driven by a lower volume of inventory withdrawn from storage for which write-downs had previously been recorded.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $0.3 million increase in natural gas margins period over period. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply, storage, and transportation associated with natural gas sales contracts. These adjustments will reverse in future periods as contracts settle.

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Operating Income

Integrys Energy Services’ operating income decreased $42.6 million. The main driver of the decrease was the $28.7 million decrease in margins discussed above. In addition, operating expenses increased $13.9 million, driven by:


•	An $8.7 million increase in sales and marketing costs and outside service fees, primarily related to the expansion of the residential and small commercial customer segment.


•	A $5.7 million increase in payroll and employee benefit expenses, primarily related to the addition of employees as a result of the Compass Energy Services acquisition. See Note 4, "Acquisitions," for more information.

Other Income

Integrys Energy Services’ other income increased $7.2 million. The main driver of the increase was the recognition of an additional $5.7 million related to the SECA settlement received in the third quarter of 2013. See Note 21, "Regulatory Environment," for more information.

Holding Company and Other Segment Operations



	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30						Change in 2013 Over 2012
(Millions)	2013			2012			Change in 2013 Over 2012		2013			2012			Change in 2013 Over 2012
Operating loss	$	(2.7	)	$	(1.0	)	170.0	%	$	(7.8	)	$	(3.6	)	116.7	%
Other expense	(8.1		)	(7.0		)	15.7	%	(16.9		)	(21.5		)	(21.4	)%
Net loss before taxes	$	(10.8	)	$	(8.0	)	35.0	%	$	(24.7	)	$	(25.1	)	(1.6	)%

Third Quarter 2013 Compared with Third Quarter 2012

Operating Loss

Operating loss at the holding company and other segment increased $1.7 million. Included in this amount is an increase in operating losses at ITF.

Other Expense

Other expense at the holding company and other segment increased $1.1 million. The increase was due to a $1.8 million increase in interest expense on long-term debt, driven by the issuance of $400.0 million of Junior Subordinated Notes during August 2013. See Note 10, "Long-Term Debt," for more information.

Nine Months 2013 Compared with Nine Months 2012

Operating Loss

Operating loss at the holding company and other segment increased $4.2 million. Included in this amount is an increase in operating losses at ITF.

Other Expense

Other expense at the holding company and other segment decreased $4.6 million. The decrease was driven by excise tax credits recorded at ITF in 2013 as a result of the American Taxpayer Relief Act of 2012. In addition, interest expense on long-term debt decreased, driven by lower average outstanding long-term debt.

Provision for Income Taxes



	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012
Effective Tax Rate	31.4	%	28.5	%	36.3	%	32.2	%

Third Quarter 2013 Compared with Third Quarter 2012

Our effective tax rate increased in the third quarter of 2013. The primary driver was a $5.9 million decrease in the provision for income taxes in the third quarter of 2012 as a result of WPS's 2013 rate case settlement agreement. WPS recorded a regulatory asset after the settlement agreement authorized recovery of deferred income taxes expensed in previous years in connection with the 2010 federal health care reform. See Note 21, "Regulatory Environment," for more information.

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Nine Months 2013 Compared with Nine Months 2012

Our effective tax rate increased in 2013. In the fourth quarter of 2012, we elected to claim and subsequently received a Section 1603 Grant for WPS's Crane Creek Wind Project in lieu of production tax credits (PTCs). As a result, we no longer claim wind PTCs on any of our qualifying facilities. In 2012, our effective tax rate was also lowered by the effective settlement of certain state income tax examinations and remeasurements of uncertain tax positions included in our liability for unrecognized tax benefits. We decreased our provision for income taxes by $6.2 million in 2012, primarily related to these items. We also decreased our provision for income taxes by $5.9 million in 2012 as a result of WPS's 2013 rate case settlement agreement, as described above.

Discontinued Operations



	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30					Change in 2013 Over 2012
(Millions)	2013			2012			Change in 2013 Over 2012		2013		2012			Change in 2013 Over 2012
Discontinued operations, net of tax	$	(0.6	)	$	(8.0	)	(92.5	)%	$	4.7	$	(9.2	)	N/A

Third Quarter 2013 Compared with Third Quarter 2012

The loss from discontinued operations, net of tax, decreased $7.4 million in the third quarter of 2013. During the third quarter of 2012, Integrys Energy Services recognized after-tax losses from discontinued operations of $5.3 million related to Westwood and $2.6 million related to Beaver Falls and Syracuse. These losses were driven by impairment losses recognized on generation facilities classified as held for sale that met the criteria for discontinued operations. See Note 5, "Discontinued Operations," for more information.

Nine Months 2013 Compared with Nine Months 2012

Earnings from discontinued operations, net of tax, increased $13.9 million in 2013. In 2013, we remeasured uncertain tax positions included in our liability for unrecognized tax benefits after effectively settling certain state income tax examinations. We reduced the provision for income taxes related to this remeasurement, of which the majority was reported as discontinued operations. In 2012, Integrys Energy Services recognized after-tax losses from discontinued operations of $6.0 million related to Westwood and $4.5 million related to Beaver Falls and Syracuse. These losses were driven by impairment losses recognized on generation facilities classified as held for sale that met the criteria for discontinued operations. See Note 5, "Discontinued Operations," for more information.

LIQUIDITY AND CAPITAL RESOURCES

We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include cash balances, liquid assets, operating cash flows, access to equity and debt capital markets, and available borrowing capacity under existing credit facilities. Our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent credit rating agencies, as well as the market rates for interest. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control.

Operating Cash Flows

During the nine months ended September 30, 2013, net cash provided by operating activities was $510.9 million, compared with $544.3 million for the same period in 2012. The $33.4 million decrease in net cash provided by operating activities was driven by:


•	A $57.7 million increase in cash used to purchase natural gas that was injected into storage. The increase was driven by higher natural gas prices at our regulated utilities and increased storage volumes at Integrys Energy Services in 2013.


•	A $50.0 million payment in 2013 for WPS's early termination of a tolling agreement in connection with the purchase of Fox Energy Company LLC.


•	A $43.2 million decrease in cash from customer prepayments and credit balances.


•	A $43.1 million decrease in cash received from income taxes, primarily driven by a federal income tax refund received in 2012 for a net operating loss incurred in 2010 that was carried back to a prior year. The 2010 net operating loss was driven by bonus depreciation.


•	A $23.5 million decrease in cash at PGL and NSG due to natural gas cost under-collection activity with customers in 2013 versus natural gas cost over-collection activity with customers in 2012. The period-over-period change was driven by higher natural gas prices in 2013.


•	A $19.0 million increase in cash used for collateral, partially due to increased collateral requirements in 2013 resulting from Integrys Energy Services' acquisitions.


•	Partially offsetting this decrease in cash provided by operating activities were the following:

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◦	A $182.8 million decrease in contributions to pension and other postretirement benefit plans.


◦	A $9.5 million increase in cash received by Integrys Energy Services in settlement of certain Seams Elimination Charge Adjustment (SECA) payments made in prior years to a transmission provider. See Note 21, "Regulatory Environment," for more information.

Investing Cash Flows

Net cash used for investing activities was $821.4 million during the nine months ended September 30, 2013, compared with $448.8 million for the same period in 2012. The $372.6 million increase in net cash used for investing activities was primarily due to $391.6 million of cash used in 2013 for WPS's purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase. Also contributing to the increase was a $36.9 million increase in cash used for other capital expenditures (discussed below). These increases in net cash used were partially offset by the $69.0 million positive impact from the receipt of a Section 1603 Grant for the Crane Creek Wind Project in 2013.

Capital Expenditures

Capital expenditures by business segment for the nine months ended September 30 were as follows:



Reportable Segment (millions)	2013		2012		Change
Natural gas utility	$	268.9	$	278.6	$	(9.7	)
Electric utility	551.3		113.5		437.8
Integrys Energy Services	8.8		27.0		(18.2		)
Holding company and other	37.3		18.7		18.6
Integrys Energy Group consolidated	$	866.3	$	437.8	$	428.5

The increase in capital expenditures at the electric utility segment was primarily due to WPS's purchase of Fox Energy Company LLC in 2013. Capital expenditures at the electric utility segment also increased related to environmental compliance projects at the Columbia plant.

Financing Cash Flows

Net cash provided by financing activities was $306.3 million during the nine months ended September 30, 2013, compared with $112.1 million of net cash used for financing activities for the same period in 2012. The $418.4 million period-over-period positive impact from financing activities was driven by:


•	A $537.2 million net increase in cash due to a $696.0 million increase in the issuance of long-term debt, which was partially offset by a $158.8 million increase in the repayment of long-term debt.


•	WPS borrowed $200.0 million under its term credit facility in 2013 to partially finance the acquisition of Fox Energy Company LLC.


•	An $83.1 million decrease in cash used to purchase shares of our common stock on the open market to satisfy stock-based compensation obligations. We began issuing new shares to meet these obligations in February 2013.

These increases were partially offset by a $401.4 million decrease in cash from $294.4 million of net repayments of commercial paper in 2013, compared with $107.0 million of net borrowings in 2012.

Significant Financing Activities

The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:



Period		Method of meeting requirements
Beginning 02/05/2013		Issuing new shares
01/01/2012 – 02/04/2013		Purchased shares on the open market

For information on short-term debt, see Note 9, "Short-Term Debt and Lines of Credit."

For information on the issuance and redemption of long-term debt in 2013, see Note 10, "Long-Term Debt."

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Credit Ratings

Our current credit ratings and the credit ratings for WPS, PGL, and NSG are listed in the table below:



Credit Ratings	Standard & Poor's	Moody's
Integrys Energy Group
Issuer credit rating	A-	N/A
Senior unsecured debt	BBB+	Baa1
Commercial paper	A-2	P-2
Junior subordinated notes	BBB	Baa2

WPS
Issuer credit rating	A-	A2
First mortgage bonds	N/A	Aa3
Senior secured debt	A	Aa3
Preferred stock	BBB	Baa1
Commercial paper	A-2	P-1

PGL
Issuer credit rating	A-	A3
Senior secured debt	A	A1
Commercial paper	A-2	P-2

NSG
Issuer credit rating	A-	A3
Senior secured debt	A	A1

Credit ratings are not recommendations to buy or sell securities. They are subject to change, and each rating should be evaluated independently of any other rating.

On February 15, 2013, Standard & Poor's raised PGL's senior secured debt rating to "A" from "A-." PGL's revised rating reflects Standard & Poor's revision to its methodology for assigning recovery ratings for senior bonds secured by utility real property.

Discontinued Operations

These cash flows primarily relate to the effective settlement of tax positions reported in the holding company and other segment. In addition, these cash flows include the operations of WPS Beaver Falls Generation, LLC, WPS Syracuse Generation, LLC, and Combined Locks Energy Center, LLC. The 2012 cash flows also include the operations of WPS Westwood Generation, LLC. See Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Discontinued Operations," and Note 5, "Discontinued Operations," for more information.

Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of September 30, 2013, including those of our subsidiaries:



			Payments Due By Period
(Millions)	Total Amounts Committed		2013		2014 to 2015		2016 to 2017		2018 and Later Years
Long-term debt principal and interest payments⁽¹⁾	$	5,635.6	$	210.2	$	471.9	$	701.2	$	4,252.3
Operating lease obligations	91.9		2.2		12.9		13.2		63.6
Energy and transportation purchase obligations⁽²⁾	2,380.5		253.4		949.9		366.0		811.2
Purchase orders ⁽³⁾	770.9		589.5		160.4		15.0		6.0
Capital contributions to equity method investment	3.4		3.4		—		—		—
Pension and other postretirement funding obligations⁽⁴⁾	537.6		36.2		170.6		60.8		270.0
Uncertain tax positions	0.8		0.8		—		—		—
Total contractual cash obligations	$	9,420.7	$	1,095.7	$	1,765.7	$	1,156.2	$	5,403.1


⁽¹⁾	Represents bonds and notes issued, as well as loans made to us and our subsidiaries. We record all principal obligations on the balance sheet. For purposes of this table, it is assumed that the current interest rates on variable rate debt will remain in effect until the debt matures.

⁽²⁾

Energy and related commodity supply contracts at Integrys Energy Services included as part of energy and transportation purchase obligations are primarily entered into to meet future obligations to deliver energy and related products to customers; therefore, these costs will be recovered as customer sales contracts settle. The utility subsidiaries expect to recover the costs of their contracts in future customer rates.


⁽³⁾	Includes obligations related to normal business operations and large construction obligations.


⁽⁴⁾	Obligations for pension and other postretirement benefit plans, other than the Integrys Energy Group Retirement Plan, cannot reasonably be estimated beyond 2017.

The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $612.1 million at September 30, 2013, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 12, "Commitments and Contingencies," for more information about environmental liabilities. The table also does not reflect estimated future payments for the September 30, 2013 liability of $2.2 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 11, "Income Taxes," for more information about unrecognized tax benefits.

Capital Requirements

Projected capital expenditures by segment for 2013 through 2015, including amounts expended through September 30, 2013, are as follows:



(Millions)
Natural Gas Utility
Distribution projects and underground storage facilities	$	1,214
Other projects	71

Electric Utility
Environmental projects *	426
Acquisition of Fox Energy Center	392
Distribution and energy supply operations projects	335
Other projects	58

Integrys Energy Services
Renewable energy and other projects	151

Holding Company and Other
Compressed natural gas fueling stations	142
Corporate or shared services software and infrastructure projects	152
Repairs and safety measures at nonutility hydroelectric facilities	3
Total capital expenditures	$	2,944


*	This primarily relates to the installation of ReACT^TM emission control technology at Weston 3 and the installation of scrubbers at the Columbia plant.

We expect to provide capital contributions to ATC (not included in the above table) of approximately $48 million from 2013 through 2015.

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All projected capital and investment expenditures are subject to periodic review and may vary significantly from the estimates, depending on a number of factors. These factors include, but are not limited to, environmental requirements, regulatory constraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends.

Capital Resources

Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management policies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage the liquidity and capital resource needs of the business segments. We plan to meet our capital requirements for the period 2013 through 2015 primarily through internally generated funds (net of forecasted dividend payments) and debt and equity financings. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.

Under an existing shelf registration statement, we may issue debt, equity, certain types of hybrid securities, and other financial instruments with amounts, prices, and terms to be determined at the time of future offerings.

WPS currently has two shelf registration statements. Under these registration statements, WPS may issue up to $500.0 million of additional senior debt securities and up to $30.0 million of preferred stock. Amounts, prices, and terms will be determined at the time of future offerings.

At September 30, 2013, we and each of our subsidiaries were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 9, "Short-Term Debt and Lines of Credit," for more information on credit facilities and other short-term credit agreements. See Note 10, "Long-Term Debt," for more information on long-term debt.

Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our regulated utility subsidiaries to transfer funds to us in the form of dividends. Our regulated utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. Although these restrictions limit the amount of funding the various operating subsidiaries can provide to us, management does not believe these restrictions will have a significant impact on our ability to access cash for payment of dividends on common stock or other future funding obligations. See Note 16, "Common Equity," for more information on dividend restrictions.

Other Future Considerations

Decoupling

In 2012, the Illinois Attorney General and Citizens Utility Board appealed the ICC's authority to approve PGL's and NSG's permanent decoupling mechanism. As a result, revenues collected under this mechanism were potentially subject to refund. In 2012, PGL and NSG established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Illinois Appellate Court affirmed the ICC's authority to approve the permanent decoupling mechanism. Therefore, PGL's and NSG's permanent decoupling mechanism is in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to appeal the Court's decision. The Illinois Supreme Court granted the request in September 2013. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse Illinois Supreme Court decision.

See Note 21, "Regulatory Environment," for more information on all of our subsidiaries' decoupling mechanisms.

Climate Change

The EPA began regulating greenhouse gas emissions under the Clean Air Act in January 2011 by applying the Best Available Control Technology (BACT) requirements (associated with the New Source Review program) to new and modified larger greenhouse gas emitters. Technology to remove and sequester greenhouse gas emissions is not commercially available at scale. Therefore, the EPA issued guidance that defines BACT in terms of improvements in energy efficiency as opposed to relying on pollution control equipment. In March 2012, the EPA issued a proposed rule that would impose a carbon dioxide emission rate limit on new electric generating units. The proposed limit may prevent the construction of new coal units until technology becomes commercially available.

As directed by President Obama in June 2013, the EPA re-proposed the rules related to emission limits on new electric generating units in September 2013, and is expected to finalize them in a timely manner. The EPA was also directed to propose a rule for existing units by no later than June 1, 2014, and issue a final rule by June 1, 2015, with state implementation plans due by June 30, 2016. Facility compliance deadlines will be included in the final state plans.

A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels. However, we believe that capital expenditures being made at our plants are appropriate under any reasonable mandatory greenhouse gas program. We also believe that our future expenditures that may be required to control greenhouse gas emissions or meet renewable portfolio standards will be recoverable in rates. We will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas legislative or regulatory actions.

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The majority of our generation and distribution facilities are located in the upper Midwest region of the United States. The same is true for most of our customers' facilities. The physical risks, if any, posed by climate change for these areas are not expected to be significant at this time. Ongoing evaluations will be conducted as more information on the extent of such physical changes becomes available.

Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank Act was signed into law in July 2010. The final Commodity Futures Trading Commission (CFTC) rulemakings, which are essential to the Dodd-Frank Act's new framework for swaps regulation, have become effective or are becoming effective for certain companies and certain transactions. Some of the rules have not been finalized yet, are being challenged in court, or are subject to ongoing interpretations, clarifications, no-action letters, and other guidance being issued by the CFTC and its staff. As a result, it is difficult to predict how the CFTC's final Dodd-Frank Act rules will ultimately affect us. Certain provisions of the Dodd-Frank Act relating to derivatives could significantly increase our regulatory costs and/or collateral requirements, including the derivatives we use to hedge our commercial risks. We continue to monitor developments related to the Dodd-Frank Act rulemakings and their potential impacts on our future financial results. We continue to make the necessary systems and process changes to be in a position to comply with the rules within the CFTC's implementation timelines.

Tax Law Changes

In January 2013, President Obama signed into law the American Taxpayer Relief Act of 2012. This act extends 50% bonus tax depreciation through 2013 for most capital expenditures. This bonus tax depreciation extension is anticipated to generate future cash flows in excess of $90 million through 2015.

In June 2013, Governor Walker signed into law a three-year budget bill, 2013 Wisconsin Act 20, which is effective January 1, 2014. Among other provisions, this Act will conform the Wisconsin tax code to the federal tax code with respect to tax depreciation and basis differences. This tax law change will accelerate the generation of future cash flows in excess of $15 million over a five-year amortization period through 2018.

In September 2013, the IRS issued final and proposed tangible property regulations. These regulations are broad and affect a multitude of items. The most substantial area of the regulations is determining if an expenditure related to tangible property is a repair or should be capitalized. In recent years, our utilities filed changes in the method of accounting related to repairs of public utility property. We believe the previously filed method changes are materially consistent with the regulations as issued. Therefore, the issuance of the regulations is not expected to have a material effect on our financial position. In the near future, the IRS is expected to issue guidance on both the general implementation of the regulations and specific guidance related to one or more types of public utility property. We will continue to monitor future guidance and will consider impacts on our tax accounts when issued.

The Natural Gas Consumer, Safety & Reliability Act

In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives certain natural gas utilities, including PGL, a cost recovery mechanism for Illinois natural gas infrastructure upgrades that will be collected through a surcharge on customer bills. Later in July 2013, the ICC adopted emergency rules to implement the law. The ICC also opened a docket to develop permanent rules, which will replace the emergency rules. This Act eliminates a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation once PGL obtains an infrastructure tariff. In September 2013, PGL filed with the ICC requesting the proposed rider, and the ICC must act no later than January 17, 2014. The ICC may modify the rider only to ensure compliance with the law. The rider would take effect on January 1 of the year in which the ICC issues its order.

CRITICAL ACCOUNTING POLICIES

We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require any additional disclosures. We have found that the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2012, are still current and that there have been no significant changes, except as follows:

Goodwill Impairment

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of April 1, 2013. No impairment was recorded as a result of these tests. See Note 8, "Goodwill and Other Intangible Assets," for our goodwill balances by segment. For all of our reporting units, the fair value calculated in step one of the test was greater than the carrying value. The fair value was calculated using an equal weighting of the income approach and the market approach.

For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the fair value of a reporting unit. For the regulated reporting units, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair value of these reporting units to decrease.

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Key assumptions used in the income approach included return on equity (ROE) for the regulated reporting units, long-term growth rates used to determine terminal values at the end of the discrete forecast period, and discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is determined based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is based on its current allowed ROE adjusted for forecasted disallowed costs and expectations regarding the direction and magnitude of movements in interest rates. The terminal growth rate is based on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.

We used the guideline company method for the market approach. This method uses metrics from similar publicly traded companies in the same industry to determine how much a knowledgeable investor in the marketplace would be willing to pay for an investment in a similar company. We applied multiples derived from these guideline companies to the appropriate operating metric for the utility reporting units to determine indications of fair value.

The underlying assumptions and estimates used in the impairment test are made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the test.

The fair values of the WPS natural gas utility, Integrys Energy Services, and ITF reporting units exceeded the carrying values by a substantial amount. Based on these results, these reporting units are not at risk of failing step one of the goodwill impairment test.

The fair values calculated in the first step of the test for MERC, MGU, NSG, and PGL exceeded the carrying values by approximately 3%-19%. Due to the subjectivity of the assumptions and estimates underlying the impairment analyses, we cannot provide assurance that future analyses will not result in impairments. As a result, we performed a sensitivity analysis on key assumptions for these reporting units. The following table shows the change in each assumption, holding all other inputs constant, which would result in a fair value at or below carrying value, causing the applicable reporting unit to fail step one of the test. Failing step one would result in a goodwill impairment that could be material, as the carrying value of the identifiable assets and liabilities is considered fair value for regulated companies. This is because a regulator would typically not allow the assets and liabilities of a regulated company to be increased or decreased, allowing for a change in recovery from ratepayers, as a result of an acquisition or other change in ownership.



Change in key inputs (in basis points)	MERC		MGU		NSG		PGL
Discount rate	30		20		280		120
Terminal year return on equity	(220	)	(180	)	(535	)	(387	)
Terminal year growth rate	(25	)	(25	)	N/A *		(125	)


*	Even with a terminal year growth rate of 0%, assuming all other inputs remained constant, NSG would still have passed the first step of the goodwill impairment test.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We have potential market risk exposure related to commodity price risk, interest rate risk, and equity return and principal preservation risk. We are also exposed to other significant risks due to the nature of our subsidiaries’ businesses and the environment in which we operate. We have risk management policies in place to monitor and assist in controlling these risks, and we use derivative and other instruments to manage some of these exposures, as further described below.

Commodity Price Risk

To measure commodity price risk exposure, we employ a number of controls and processes, including a value-at-risk (VaR) analysis of certain of our exposures. Integrys Energy Services’ VaR is calculated using nondiscounted positions with a delta-normal approximation based on a one-day holding period and a 95% confidence level, as well as a ten-day holding period and a 99% confidence level. For further explanation of our VaR calculation, see our 2012 Annual Report on Form 10-K.

The VaR for Integrys Energy Services’ open commodity positions at a 95% confidence level with a one-day holding period is presented in the following table:



(Millions)	2013		2012
As of September 30	$	0.1	$	0.2
Average for 12 months ended September 30	0.2		0.1
High for 12 months ended September 30	0.2		0.2
Low for 12 months ended September 30	0.1		0.1

The VaR for Integrys Energy Services’ open commodity positions at a 99% confidence level with a ten-day holding period is presented below:



(Millions)	2013		2012
As of September 30	$	0.6	$	0.7
Average for 12 months ended September 30	0.7		0.5
High for 12 months ended September 30	0.9		0.7
Low for 12 months ended September 30	0.6		0.4

The average, high, and low amounts were computed using the VaR amounts at each of the four quarter ends.

Interest Rate Risk

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.

Based on the variable rate debt outstanding at September 30, 2013, a hypothetical increase in market interest rates of 100 basis points would have increased annual interest expense by $3.9 million. Comparatively, based on the variable rate debt outstanding at September 30, 2012, an increase in interest rates of 100 basis points would have increased annual interest expense by $4.4 million. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Other than the above-mentioned changes, our market risks have not changed materially from the market risks reported in our 2012 Annual Report on Form 10-K.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of Integrys Energy Group's disclosure controls and procedures (as defined by Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based upon that evaluation, management, including our Chief Executive Officer and Chief Financial Officer, has concluded that Integrys Energy Group's disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control

There were no changes in our internal control over financial reporting (as defined by Securities Exchange Act Rules 13a-15(f) and 15d-15(f)) during the quarter ended September 30, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information on material legal proceedings and matters, see Note 12, "Commitments and Contingencies."

Item 1A. Risk Factors

There were no material changes in the risk factors previously disclosed in Part I, Item 1A of our 2012 Annual Report on Form 10-K, which was filed with the SEC on March 1, 2013.

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

Dividend Restrictions

We are a holding company and our ability to pay dividends is largely dependent upon the ability of our subsidiaries to make payments to us in the form of dividends or otherwise. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note 16, "Common Equity."

Issuer Purchases of Equity Securities

As of February 5, 2013, we began issuing new shares of common stock to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans. Prior to this date, shares were purchased in the open market to meet the requirements of these plans. There were no common stock purchases during the three months ended September 30, 2013.

Item 6. Exhibits

The documents listed in the Exhibit Index are attached as exhibits or incorporated by reference herein.

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SIGNATURE

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



	INTEGRYS ENERGY GROUP, INC.
	(Registrant)

Date: November 7, 2013	/s/ Linda M. Kallas
	Linda M. Kallas
	Vice President and Controller

	(Duly Authorized Officer and Chief Accounting Officer)

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INTEGRYS ENERGY GROUP

EXHIBIT INDEX TO FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2013



Exhibit No.		Description

4		Second Supplemental Indenture, dated as of August 15, 2013, between Integrys Energy Group, Inc. and U.S. Bank National Association, as Trustee (Incorporated by reference to Exhibit 4.2 to Form 8-A filed on August 15, 2013).

31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Integrys Energy Group, Inc.

31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Integrys Energy Group, Inc.

32		Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Integrys Energy Group, Inc.

101		Financial statements from the Quarterly Report on Form 10-Q of Integrys Energy Group, Inc. for the quarter ended September 30, 2013, formatted in eXtensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income, (ii) the Condensed Consolidated Statements of Comprehensive Income, (iii) the Condensed Consolidated Balance Sheets, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Notes To Financial Statements, and (vi) document and entity information.