UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

OR

oTRANSITION 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	Internal Revenue Service  Employer Identification No.
1-3016	WISCONSIN PUBLIC SERVICE CORPORATION (A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 800-450-7260	39-0715160

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 o

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 o

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

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes o No 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, $4 par value,

23,896,962 shares outstanding at

October 30, 2012

WISCONSIN PUBLIC SERVICE CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2012

TABLE OF CONTENTS

				Page
	FORWARD-LOOKING STATEMENTS			1
PART I.	FINANCIAL INFORMATION			2
ITEM 1.	FINANCIAL STATEMENTS (Unaudited)			2
	Condensed Consolidated Statements of Income			2
	Condensed Consolidated Balance Sheets			3
	Condensed Consolidated Statements of Capitalization			4
	Condensed Consolidated Statements of Cash Flows			5
	CONDENSED NOTES TO FINANCIAL STATEMENTS OF Wisconsin Public Service Corporation and Subsidiary			6 – 21
			Page
	Note 1	Financial Information	6
	Note 2	Cash and Cash Equivalents	6
	Note 3	Risk Management Activities	6
	Note 4	Agreement to Purchase Fox Energy Center	8
	Note 5	Short-Term Debt and Lines of Credit	8
	Note 6	Long-Term Debt	9
	Note 7	Income Taxes	9
	Note 8	Commitments and Contingencies	9
	Note 9	Employee Benefit Plans	13
	Note 10	Stock-Based Compensation	13
	Note 11	Common Equity	15
	Note 12	Variable Interest Entities	16
	Note 13	Fair Value	16
	Note 14	Miscellaneous Income	18
	Note 15	Regulatory Environment	18
	Note 16	Segments of Business	19
	Note 17	New Accounting Pronouncements	20
	Note 18	Related Party Transactions	21
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			22 – 32
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			33
ITEM 4.	Controls and Procedures			34
PART II.	OTHER INFORMATION			35
ITEM 1.	Legal Proceedings			35
ITEM 1A.	Risk Factors			35
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			35
ITEM 6.	Exhibits			35
Signature				36
EXHIBIT INDEX				37

i

Commonly Used Acronyms in this Quarterly Report on Form 10-Q

AFUDC	Allowance for Funds Used During Construction
ASU	Accounting Standards Update
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
MISO	Midwest Independent Transmission System Operator, Inc.
N/A	Not Applicable
NYMEX	New York Mercantile Exchange
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
WRPC	Wisconsin River Power Company

ii

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, but rather are subject to numerous management assumptions, risks, and uncertainties. Therefore, actual results may differ materially from those expressed or implied by these statements. 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, 2011, 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 us;

· Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting coal-fired 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 subsidiary are subject;

· Costs and effects of litigation and administrative proceedings, settlements, investigations, and claims, including manufactured gas plant site cleanup, third-party intervention in permitting and licensing projects, and compliance with Clean Air Act requirements at generation plants;

· Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our 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 we operate;

· 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 customers;

· Potential business strategies, including 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 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 effect of accounting pronouncements issued periodically by standard-setting bodies; and

· Other factors discussed elsewhere herein and in other reports we and/or Integrys Energy Group 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.

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

WISCONSIN PUBLIC SERVICE CORPORATION

	Three Months Ended						Nine Months Ended
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	September 30						September 30
(Millions)	2012			2011			2012			2011
Operating revenues	$	378.1		$	376.8		$	1,119.8		$	1,169.6
Cost of fuel, natural gas, and purchased power	175.0			168.2			517.4			545.9
Operating and maintenance expense	103.0			109.7			316.3			333.9
Depreciation and amortization expense	24.1			23.9			72.0			71.6
Taxes other than income taxes	11.7			11.8			36.0			36.0
Operating income	64.3			63.2			178.1			182.2
Miscellaneous income	3.8			2.9			11.4			10.1
Interest expense	(10.5		)	(11.1		)	(31.9		)	(39.4		)
Other expense	(6.7		)	(8.2		)	(20.5		)	(29.3		)
Income before taxes	57.6			55.0			157.6			152.9
Provision for income taxes	14.4			19.7			48.1			54.9
Net income	43.2			35.3			109.5			98.0
Preferred stock dividend requirements	(0.7		)	(0.7		)	(2.3		)	(2.3		)
Net income attributed to common shareholder	$	42.5		$	34.6		$	107.2		$	95.7

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

2

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	September 30		December 31
(Millions)	2012		2011
Assets
Cash and cash equivalents	$	4.9	$	5.5
Accounts receivable and accrued unbilled revenues, net of reserves of $4.0 and $3.0, respectively	162.0		199.5
Receivables from related parties	5.3		4.6
Inventories
Fuel and gas	78.2		90.7
Materials and supplies, at average cost	34.2		28.7
Regulatory assets	29.7		44.6
Prepaid taxes	62.2		112.6
Other current assets	12.1		11.6
Current assets	388.6		497.8
Property, plant, and equipment, net of accumulated depreciation of $1,335.6 and $1,280.7, respectively	2,398.6		2,340.1
Regulatory assets	459.9		454.3
Receivables from related parties	—		12.8
Goodwill	36.4		36.4
Other long-term assets	93.9		86.1
Total assets	$	3,377.4	$	3,427.5
Liabilities and Shareholders’ Equity
Short-term debt	$	174.3	$	173.7
Current portion of long-term debt	172.0		150.0
Accounts payable	106.0		114.6
Payables to related parties	15.5		14.1
Regulatory liabilities	25.4		19.1
Other current liabilities	69.9		61.8
Current liabilities	563.1		533.3
Long-term debt to parent	7.4		7.9
Long-term debt	549.4		571.3
Deferred income taxes	513.1		476.1
Deferred investment tax credits	8.4		8.7
Regulatory liabilities	269.4		256.3
Environmental remediation liabilities	69.8		67.6
Pension and other postretirement benefit obligations	140.0		272.8
Payables to related parties	6.9		7.4
Other long-term liabilities	75.7		72.8
Long-term liabilities	1,640.1		1,740.9
Commitments and contingencies
Preferred stock - $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding	51.2		51.2
Common stock - $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding	95.6		95.6
Additional paid-in capital	555.0		561.9
Retained earnings	472.4		444.6
Total liabilities and shareholders’ equity	$	3,377.4	$	3,427.5

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

3

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION (Unaudited)				September 30			December 31
(Millions, except share amounts)				2012			2011
Common stock equity
Common stock - $4 par value; 32,000,000 shares authorized; 23,896,962 shares outstanding				$	95.6		$	95.6
Additional paid-in capital				555.0			561.9
Retained earnings				472.4			444.6
Total common stock equity				1,123.0			1,102.1
Preferred stock
Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption -
	Series		Shares Outstanding
	5.00	%	131,916	13.2			13.2
	5.04	%	29,983	3.0			3.0
	5.08	%	49,983	5.0			5.0
	6.76	%	150,000	15.0			15.0
	6.88	%	150,000	15.0			15.0
Total preferred stock				51.2			51.2
Long-term debt to parent
	Series		Year Due
	8.76	%	2015	2.9			3.1
	7.35	%	2016	4.5			4.8
Total long-term debt to parent				7.4			7.9
Long-term debt
First Mortgage Bonds
	Series		Year Due
	7.125	%	2023	0.1			0.1
Senior Notes
	Series		Year Due
	4.875	%	2012	150.0			150.0
	3.95	%	2013	22.0			22.0
	4.80	%	2013	125.0			125.0
	6.375	%	2015	125.0			125.0
	5.65	%	2017	125.0			125.0
	6.08	%	2028	50.0			50.0
	5.55	%	2036	125.0			125.0
Total First Mortgage Bonds and Senior Notes				722.1			722.1
Unamortized discount on long-term debt				(0.7		)	(0.8		)
Total				721.4			721.3
Current portion of long-term debt				(172.0		)	(150.0		)
Total long-term debt				549.4			571.3
Total capitalization				$	1,731.0		$	1,732.5

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

4

WISCONSIN PUBLIC SERVICE CORPORATION

	Nine Months Ended
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	September 30
(Millions)	2012			2011
Operating Activities
Net income	$	109.5		$	98.0
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	72.0			71.6
Recoveries and refunds of regulatory assets and liabilities	11.4			23.2
Bad debt expense	4.1			5.0
Pension and other postretirement expense	14.3			16.3
Pension and other postretirement contributions	(109.5		)	(61.6		)
Deferred income taxes and investment tax credits	23.4			31.5
Repayment of related party payable	(22.6		)	—
Equity income, net of dividends	(0.8		)	(0.7		)
Other	1.9			13.3
Changes in working capital
Collateral on deposit	(0.4		)	0.6
Accounts receivable and accrued unbilled revenues	31.3			36.2
Inventories	10.2			(32.1		)
Prepaid taxes	50.4			1.2
Other current assets	(1.8		)	5.2
Accounts payable	(12.5		)	(12.0		)
Other current liabilities	29.6			(4.3		)
Net cash provided by operating activities	210.5			191.4
Investing Activities
Capital expenditures	(126.0		)	(67.8		)
Proceeds from the sale or disposal of assets	2.3			2.0
Other	3.4			1.9
Net cash used for investing activities	(120.3		)	(63.9		)
Financing Activities
Short-term debt, net	0.6			120.3
Repayment of notes payable	—			(10.0		)
Repayment of long-term debt to parent	(0.5		)	(0.5		)
Repayment of long-term debt	—			(150.0		)
Dividends to parent	(79.1		)	(76.9		)
Equity contribution from parent	40.0			—
Return of capital to parent	(50.0		)	(75.0		)
Preferred stock dividend requirements	(2.3		)	(2.3		)
Other	0.5			0.8
Net cash used for financing activities	(90.8		)	(193.6		)
Net change in cash and cash equivalents	(0.6		)	(66.1		)
Cash and cash equivalents at beginning of period	5.5			71.4
Cash and cash equivalents at end of period	$	4.9		$	5.3

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

5

WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY

CONDENSED NOTES TO FINANCIAL STATEMENTS

September 30, 2012

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 balance sheets, condensed consolidated statements of capitalization, 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 WPS.

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, 2011.

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. Financial results for an interim period may not give a true indication of results for the year.

Reclassification

We adjusted changes in working capital on the statements of cash flows by reclassifying $6.5 million related to materials and supplies at September 30, 2011, from the change in other current assets line item to the change in inventories line item to be consistent with the current period presentation. This reclassification had no impact on total cash flows from operating activities.

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)	2012			2011
Cash paid for interest	$	20.8		$	29.8
Cash (received) paid for income taxes	(14.2		)	31.8

Construction costs funded through accounts payable totaled $15.8 million at September 30, 2012, and $7.6 million at September 30, 2011. These costs were treated as noncash investing activities.

NOTE 3—RISK MANAGEMENT ACTIVITIES

We use derivative instruments to manage commodity costs. None of these derivatives are designated as hedges for accounting purposes. The derivatives include physical commodity contracts and NYMEX futures and options used by both the electric and natural gas utility segments to manage the risks associated with the market price volatility of natural gas costs and the costs of gasoline and diesel fuel used by our utility vehicles. The electric utility segment also uses financial transmission rights (FTRs) to manage electric transmission congestion costs and NYMEX oil futures and options to reduce price risk related to coal transportation.

6

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

	Balance Sheet	September 30, 2012
(Millions)	Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	1.1	$	0.2
Natural gas contracts	Other Long-term	0.1		—
FTRs	Other Current	1.9		0.2
Petroleum product contracts	Other Current	0.2		—
Coal contract	Other Current	—		5.0
Coal contract	Other Long-term	—		4.3
Total commodity contracts	Other Current	$	3.2	$	5.4
Total commodity contracts	Other Long-term	$	0.1	$	4.3

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

	Balance Sheet	December 31, 2011
(Millions)	Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	0.1	$	2.5
FTRs	Other Current	1.3		0.1
Petroleum product contracts	Other Current	0.1		—
Coal contract	Other Current	—		2.5
Coal contract	Other Long-term	—		4.4
Total commodity contracts	Other Current	$	1.5	$	5.1
Total commodity contracts	Other Long-term	$	—	$	4.4

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

The following table shows the unrealized gains (losses) recorded related to derivatives:

		Three Months Ended  September 30						Nine Months Ended September 30
(Millions)	Financial Statement Presentation	2012			2011			2012			2011
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	0.3		$	(1.7	)	$	2.8		$	0.7
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	0.3			(0.1		)	0.6			(0.2		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.1			—			0.1			—
Natural gas contracts	Income Statement — Cost of fuel, natural gas, and purchased power	0.1			(0.1		)	0.2			—
FTRs	Balance Sheet — Regulatory assets (current)	—			0.2			(0.6		)	(0.5		)
FTRs	Balance Sheet — Regulatory liabilities (current)	—			(0.5		)	0.3			(0.4		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	0.2			—			0.1			(0.1		)
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	0.1			(0.2		)	0.1			—
Petroleum product contracts	Income Statement — Operating and maintenance expense	—			(0.1		)	—			—
Coal contract	Balance Sheet — Regulatory assets (current)	0.7			1.1			(2.5		)	0.9
Coal contract	Balance Sheet — Regulatory assets (long-term)	(0.1		)	2.4			0.1			(0.6		)
Coal contract	Balance Sheet — Regulatory liabilities (long-term)	—			0.5			—			(3.2		)

We had the following notional volumes of outstanding derivative contracts:

	September 30, 2012		December 31, 2011
Commodity	Purchases	Other  Transactions	Purchases	Other  Transactions
Natural gas (millions of therms)	112.8	N/A	58.4	N/A
FTRs (millions of kilowatt-hours)	N/A	6,155.6	N/A	4,814.8
Petroleum products (barrels)	32,695.0	N/A	26,770.0	N/A
Coal contract (millions of tons)	3.5	N/A	4.1	N/A

7

The following table shows our cash collateral positions:

(Millions)	September 30, 2012		December 31, 2011
Cash collateral provided to others	$	4.0	$	4.1

NOTE 4—AGREEMENT TO PURCHASE FOX ENERGY CENTER

In September 2012, we entered into an agreement to acquire all of the equity interests in Fox Energy Company LLC. The purchase includes the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility in Wisconsin, along with associated contracts. We currently supply natural gas for the facility and purchase 500 megawatts of capacity and the associated energy output under a tolling arrangement.

We will pay $390.0 million to purchase Fox Energy Company LLC, subject to post-closing adjustments, primarily related to working capital. In addition, we will pay $50.0 million to terminate the existing tolling arrangement immediately prior to the acquisition of the facility. The purchase will be financed initially with a combination of short-term debt, cash flow from operations, and an infusion of equity from our parent company. The short-term debt will be replaced later in 2013 with long-term financing.

Fox Energy Center is a dual-fuel facility, equipped to use fuel oil but expected to run primarily on natural gas. This plant will give us a more balanced mix of electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources.

The transaction is subject to state regulatory approvals, including cost recovery, FERC approvals, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The transaction is expected to close on or around April 1, 2013.

NOTE 5—SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings were as follows:

(Millions, except percentages)	September 30, 2012			December 31, 2011
Commercial paper outstanding	$	174.3		$	173.7
Average discount rate on outstanding commercial paper	0.24		%	0.26		%

The commercial paper outstanding at September 30, 2012, had maturity dates ranging from October 1, 2012, through October 24, 2012.

The table below presents our average amount of short-term borrowings outstanding based on daily outstanding balances during the nine months ended September 30:

(Millions)	2012		2011
Average amount of commercial paper outstanding	$	156.3	$	33.1
Average amount of short-term notes payable outstanding	—		4.8

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

(Millions)	Maturity	September 30, 2012		December 31, 2011
Revolving credit facility (1)	04/23/13	$	—	$	115.0
Revolving credit facility (2)	06/12/13	115.0		—
Revolving credit facility	05/17/14	135.0		135.0
Total short-term credit capacity		$	250.0	$	250.0
Less:
Letters of credit issued inside credit facilities		$	—	$	0.2
Commercial paper outstanding		174.3		173.7
Available capacity under existing agreements		$	75.7	$	76.1

(1)     This credit facility was terminated in June 2012.

(2)     We requested approval from the PSCW to extend this facility through June 13, 2017.

In connection with the pending purchase of Fox Energy Company LLC, we requested approval from the PSCW to temporarily increase our short-term debt limit. See Note 4, “Agreement to Purchase Fox Energy Center,” for more information regarding this pending purchase.

8

NOTE 6—LONG-TERM DEBT

See our statements of capitalization for details on our long-term debt.

In December 2012, our 4.875% Senior Notes will mature. As a result, the $150.0 million balance of these notes was included in the current portion of long-term debt on our balance sheets.

In February 2013, our 3.95% Senior Notes will mature. As a result, the $22.0 million balance of these notes was included in the current portion of long-term debt on our September 30, 2012, balance sheet.

NOTE 7—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:

	Three Months Ended  September 30				Nine Months Ended  September 30
	2012		2011		2012		2011
Effective Tax Rate	25.0	%	35.8	%	30.5	%	35.9	%

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

Our effective tax rates for the three and nine months ended September 30, 2012, were impacted by a $5.9 million decrease in the provision for income taxes resulting from our 2013 rate case settlement agreement. In the third quarter of 2012, we 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 15, “Regulatory Environment,” for more information. Our effective tax rates were also impacted by the federal income tax benefit of tax credits related to wind production and other miscellaneous tax adjustments.

Our effective tax rates for the three and nine months ended September 30, 2011, were impacted by the federal income tax benefit of tax credits related to wind production.

During the three and nine months ended September 30, 2012, there was not a significant change in our liability for unrecognized tax benefits.

NOTE 8—COMMITMENTS AND CONTINGENCIES

Commodity Purchase Obligations and Purchase Order Commitments

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates.

The purchase obligations described below were as of September 30, 2012.

· Our electric utility segment had obligations of $999.4 million for either capacity or energy related to purchased power that extend through 2029, obligations of $165.4 million related to coal supply and transportation contracts that extend through 2017, and obligations of $0.9 million for other commodities that extend through 2013.

· Our natural gas utility segment had obligations of $311.3 million related to natural gas supply and transportation contracts that extend through 2024.

· We also had commitments of $201.7 million in the form of purchase orders issued to various vendors that relate to normal business operations, including construction projects.

Environmental

Clean Air Act (CAA) New Source Review Issues

Weston and Pulliam Plants:

In November 2009, the EPA issued us a Notice of Violation (NOV) 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.

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In May 2010, we received from the Sierra Club a Notice of Intent (NOI) to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We 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 on October 6, 2012, but further action by the Sierra Club is unknown at this time.

We believe we have reached a tentative agreement with the EPA on general terms to settle these air permitting violation claims and are negotiating a consent decree based upon those general terms, which are subject to change during the negotiations. Based upon the status of the current negotiations and a review of existing EPA consent decrees, we anticipate that the final consent decree could include the installation of emission control technology, changed operating conditions (including fuels other than coal and retirement of units), limitations on emissions, beneficial supplemental environmental projects, and a civil fine. Once the final terms are agreed to, the U.S. District Court must approve the consent decree after a public comment process.

We cannot predict the final outcome of this matter because a final agreement on the consent decree may not be reached, the final terms of the consent decree may be different than currently anticipated, interveners could convince the court to make changes to the terms of the consent decree during the public comment process, or the court may not approve the final consent decree.

Any costs prudently incurred as a result of actions taken due to the consent decree are expected to be recoverable from customers. We are currently unable to estimate the possible loss or range of loss related to this matter.

Columbia and Edgewater Plants:

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 us). The NOV alleges violations of the CAA’s New Source Review requirements related to certain projects completed at those plants.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Columbia plant did not comply with the CAA. The case has been dismissed without prejudice as the parties continue to participate in settlement negotiations.

Also 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. The case was stayed until July 15, 2012, and a request was made by WP&L to further extend the stay and all deadlines. An update was filed with the court on August 31, 2012, regarding the settlement negotiations with the Sierra Club, the EPA, and the joint owners of the Edgewater plant.

WP&L, Madison Gas and Electric, and we (Joint Owners), along with the EPA and the Sierra Club (collectively, the Parties) are exploring settlement options. The Joint Owners believe that the Parties have reached a tentative agreement on general terms to settle these air permitting violation claims and are negotiating a consent decree based upon those general terms, which are subject to change during the negotiations. Based upon the status of the current negotiations and a review of existing EPA consent decrees, we anticipate that the final consent decree could include the installation of emission control technology, changed operating conditions (including fuels other than coal and retirement of units), limitations on emissions, beneficial supplemental environmental projects, and a civil fine. Once the Parties agree to the final terms, the U.S. District Court must approve the consent decree after a public comment process.

We cannot predict the final outcome of this matter because the Parties may be unable to reach a final agreement on the consent decree, the final terms of the consent decree may be different than currently anticipated, interveners could convince the court to make changes to the terms of the consent decree during the public comment process, or the court may not approve the final consent decree.

Any costs prudently incurred as a result of actions taken due to the consent decree are expected to be recoverable from customers. We are currently unable to estimate the possible loss or range of loss related to this matter.

Weston Air Permits

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, we, 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. We are working with the WDNR and the Sierra Club to resolve this issue. We do not expect this matter to have a material impact on our financial statements.

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Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit. We objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR. We continue to meet 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 permit, the WDNR intends to re-issue the draft permit for additional comments. On July 24, 2012, Clean Wisconsin filed suit against the WDNR alleging failure to issue or delay in issuing the Weston 4 Title V permit. We are not a party to this litigation, but we filed a request for intervention to protect our interests. Motions regarding intervention and dismissal have also been filed by us and the WDNR. We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, we received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant, Weston 1, Weston 2, and Weston 4, as well as one NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions have been taken for the events in the five NOVs. In December 2011, the WDNR dismissed two of the NOVs and referred the other three NOVs to the state Justice Department for enforcement. We and the Justice Department have begun discussing the pending NOVs and their resolution. We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit

The WDNR issued the renewal of the permit for the Pulliam plant in April 2009. In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 Petition requesting the EPA to object to the permit.

We also challenged the permit in a contested case proceeding and Petition for Judicial Review. The Petition was dismissed in an order remanding the matter to the WDNR. In February 2011, the WDNR granted a contested case proceeding before an Administrative Law Judge on the issues we raised, which included seeking averaging times in the emission limits in the permit. We participated in the contested case proceeding in October 2011. In December 2011, the Administrative Law Judge did not require the WDNR to insert averaging times, for which we had argued. We have decided not to appeal.

In October 2010, we received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA based on what the Sierra Club alleged to be an unreasonable delay in responding to the June 2010 order. We received notification that the Sierra Club filed suit against the EPA in April 2011. We are not a party to this litigation, but intervened to protect our interests. In February 2012, the WDNR sent a proposed permit and response to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has been entered by the court. On May 9, 2012, the Sierra Club filed another Petition requesting the EPA to again object to the proposed permit and response. The Sierra Club recently filed a request for a contested case proceeding regarding the permit, which we plan to oppose.

We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.

Columbia Title V Air Permit

In October 2009, the EPA issued an order objecting to the permit renewal issued by the WDNR for the Columbia plant. The order determined that the WDNR did not adequately analyze whether a project in 2006 constituted a “major modification that required a permit.”  The EPA’s order directed the WDNR to resolve the objections within 90 days and “terminate, modify, or revoke and reissue” the permit accordingly.

In July 2010, we, along with our co-owners, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA. The Sierra Club alleges that the EPA should assert jurisdiction over the permit because the WDNR failed to respond to the EPA’s objection within 90 days.

In September 2010, the WDNR issued a draft construction permit and a draft revised Title V permit in response to the EPA’s order. In November 2010, the EPA notified the WDNR that the EPA “does not believe the WDNR’s proposal is responsive to the order.”  In January 2011, the WDNR issued a letter stating that upon review of the submitted public comments, the WDNR has determined not to issue the draft permits that were proposed to respond to the EPA’s order. In February 2011, the Sierra Club filed for a declaratory action, claiming that the EPA had to assert jurisdiction over the permits. In May 2011, the WDNR issued a second 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 has not addressed the EPA’s objections to the Title V permit issues for the Columbia plant. The notice gave WP&L 90 days to comment on the EPA’s proposal, which was later extended by the EPA to December 15, 2012. If the EPA decides to require the submittal of an operation permit, it would be due within six months of the EPA’s notice to WP&L. WP&L believes the previously issued Title V permit for the Columbia plant is still valid. We do not expect this matter to have a material impact on our financial statements.

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Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin’s mercury rule, Chapter NR 446, requires a 40% reduction from the 2002 through 2004 baseline mercury emissions in Phase I, beginning January 1, 2010, through the end of 2014. In Phase II, which begins in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the 2002 through 2004 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 defined by the Best Available Control Technology rule. As of September 30, 2012, we estimate capital costs of approximately $2 million, which includes estimates for both wholly owned and jointly owned plants, to achieve the required Phase I and Phase II 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 rule that will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. 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:

The EPA issued the Clean Air Interstate Rule (CAIR) in 2005 in order to reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin and Michigan. In July 2008, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision vacating CAIR. In response to requests by numerous parties, including the EPA, the D.C. Circuit reinstated CAIR in December 2008, but directed the EPA to address the deficiencies noted in its previous ruling to vacate CAIR. In July 2011, the EPA issued a final CAIR replacement rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including us, challenged in the D.C. Circuit. The new rule was to become effective January 1, 2012; however, on December 30, 2011, the D.C. Circuit issued a decision that stayed the rule pending resolution of the challenges and directed the EPA to implement CAIR during the stay period. On August 21, 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. On October 5, 2012, the EPA and several other parties filed petitions for rehearing of the D.C. Circuit’s decision. Responses to those petitions are due November 16, 2012.

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 are not warranted.

Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether this will cause us to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. We expect to recover any future compliance costs in future rates.

Manufactured Gas Plant Remediation

We 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, we are required to undertake remedial action with respect to some of these materials. We 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.

We are responsible for the environmental remediation of ten sites, of which seven 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, 2012, we estimated and accrued for $69.8 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, 2012, we recorded a regulatory asset of $79.4 million, which is net of insurance recoveries received of $22.3 million, related to the expected recovery of both cash expenditures and estimated future expenditures through rates. Under current PSCW policies, we may not recover carrying costs associated with the cleanup 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. 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 rate recovery of such costs.

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NOTE 9—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						Nine Months						Three Months						Nine Months
	Ended  September 30						Ended  September 30						Ended  September 30						Ended  September 30
(Millions)	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	3.2		$	2.8		$	9.6		$	8.4		$	2.1		$	1.8		$	6.4		$	5.3
Interest cost	8.5			9.0			25.5			27.1			3.8			3.8			11.3			11.4
Expected return on plan assets	(13.8		)	(11.7		)	(41.5		)	(35.1		)	(3.6		)	(3.6		)	(10.9		)	(10.7		)
Amortization of transition obligation	—			—			—			—			0.1			0.1			0.2			0.2
Amortization of prior service cost (credit)	1.1			1.2			3.4			3.6			(0.8		)	(0.9		)	(2.3		)	(2.6		)
Amortization of net actuarial loss	3.7			2.2			11.1			6.5			1.4			0.7			4.2			2.2
Net periodic benefit cost	$	2.7		$	3.5		$	8.1		$	10.5		$	3.0		$	1.9		$	8.9		$	5.8

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 recorded as net regulatory assets.

We make contributions to our plans in accordance with legal and tax requirements. These contributions do not necessarily occur evenly throughout the year. We contributed $109.4 million to our pension plans and contributions to our other postretirement benefit plans were not significant, during the nine months ended September 30, 2012. We expect to contribute an additional $1.0 million to our pension plans and $12.3 million to our other postretirement benefit plans during the remainder of 2012, dependent upon various factors affecting us, including our liquidity position and tax law changes.

During 2012, $35.3 million of the pension obligation related to the unfunded nonqualified retirement plan was transferred to related parties. Therefore, our balance sheet at September 30, 2012 only reflects the pension liability associated with our past and current employees.

NOTE 10—STOCK-BASED COMPENSATION

Our employees may be granted awards under Integrys Energy Group’s stock-based compensation plans. Compensation cost associated with these awards is allocated to us based on the percentages used for allocation of the award recipients’ labor costs.

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)	2012		2011		2012		2011
Stock options	$	0.2	$	0.2	$	0.4	$	0.5
Performance stock rights	0.1		—		1.8		0.4
Restricted shares and restricted share units	0.8		0.7		2.7		2.6
Total stock-based compensation expense	$	1.1	$	0.9	$	4.9	$	3.5
Deferred income tax benefit	$	0.4	$	0.4	$	2.0	$	1.4

No stock-based compensation cost was capitalized during the three and nine months ended September 30, 2012, and 2011.

Stock Options

The fair value of stock option awards granted was estimated using a binomial lattice model. The expected term of option awards is calculated based on historical exercise behavior 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 of Integrys Energy Group. The expected stock price volatility was estimated using its 10-year historical volatility.

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The following table shows the weighted-average fair value per stock option granted during the nine months ended September 30, 2012, along with the assumptions incorporated into the valuation model:

	February 2012 Grant
Weighted-average fair value per option		$6.30
Expected term		5 years
Risk-free interest rate		0.17% - 2.18%
Expected dividend yield		5.28%
Expected volatility		25%

A summary of stock option activity for the nine months ended September 30, 2012, and information related to outstanding and exercisable stock options at September 30, 2012, 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, 2011	134,976		$	48.41
Granted	12,435		53.24
Exercised	(33,089	)	46.64
Transfers	(45,720	)	49.06
Outstanding at September 30, 2012	68,602		49.70		5.7	$	0.2
Exercisable at September 30, 2012	38,390		$	50.66	3.6	$	0.1

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 at September 30, 2012. This is calculated as the difference between Integrys Energy Group’s closing stock price on September 30, 2012, 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, 2012, and 2011, was not significant.

As of September 30, 2012, future compensation cost expected to be recognized for unvested and outstanding stock options was not significant.

Performance Stock Rights

The fair values of performance stock rights were 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 of Integrys Energy Group. The expected volatility was estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at September 30:

	2012
Risk-free interest rate	0.32% - 1.27%
Expected dividend yield	5.28% - 5.34%
Expected volatility	21% – 36%

A summary of the activity for the nine months ended September 30, 2012, related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-AverageFair Value(2)
Outstanding at December 31, 2011	4,629		$	46.16
Granted	840		52.70
Award modifications(1)	2,569		79.62
Distributed	(2,347	)	42.86
Adjustment for final payout	(825	)	42.86
Transfers	42		50.21
Outstanding at September 30, 2012	4,908		$	66.95

(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 Integrys Energy Group’s 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, 2012, and 2011, was $52.70 and $49.21, per performance stock right, respectively.

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A summary of the activity for the nine months ended September 30, 2012, related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2011	5,815
Granted	3,354
Award modifications*	(2,569	)
Transfers	174
Outstanding at September 30, 2012	6,774

*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 Integrys Energy Group’s 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, 2012, was $49.99 per performance stock right.

As of September 30, 2012, future compensation cost expected to be recognized for unvested and outstanding performance stock rights (equity and liability awards) was not significant.

The total intrinsic value of performance stock rights distributed during the nine months ended September 30, 2012, and 2011, was not significant.

Restricted Shares and Restricted Share Units

During the second quarter of 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at September 30, 2012.

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the nine months ended September 30, 2012, is presented below:

	Restricted ShareUnit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2011	67,227		$	45.18
Granted	23,880		53.24
Dividend equivalents	2,461		48.20
Vested and released	(27,247	)	45.12
Transfers	(113	)	45.20
Forfeited	(256	)	53.24
Outstanding at September 30, 2012	65,952		48.27

As of September 30, 2012, $1.3 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.2 years.

The total intrinsic value of restricted share and restricted share unit awards vested and released during the nine months ended September 30, 2012, and 2011, was $1.5 million and $1.0 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and releasing of restricted shares and restricted share units during the nine months ended September 30, 2012, and 2011, was not significant.

The weighted-average grant date fair value of restricted share units awarded during the nine months ended September 30, 2012, and 2011, was $53.24 and $49.40 per share, respectively.

NOTE 11—COMMON EQUITY

Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys Energy Group.

The PSCW allows us to pay dividends on our common stock of no more than 103% of the previous year’s common stock dividend. We may return capital to Integrys Energy Group if our average financial common equity ratio is at least 50.24% on a calendar year basis. We must obtain PSCW approval if a return of capital would cause our average financial common equity ratio to fall below this level. Integrys Energy Group’s right to receive dividends on our common stock is also subject to the prior rights of our preferred

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shareholders and to provisions in our restated articles of incorporation, which limit the amount of common stock dividends that we may pay if our common stock and common stock surplus accounts constitute less than 25% of our total capitalization.

Our short-term debt obligations 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.

As of September 30, 2012, total restricted net assets were $1,100.4 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $27.0 million at September 30, 2012.

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

Integrys Energy Group may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of Integrys Energy Group or its other subsidiaries. During the nine months ended September 30, 2012, we received $40.0 million of equity contributions from Integrys Energy Group, paid common stock dividends of $79.1 million to Integrys Energy Group, and returned $50.0 million of capital to Integrys Energy Group.

NOTE 12—VARIABLE INTEREST ENTITIES

We have a variable interest in an entity through a power purchase agreement relating to the cost of fuel. This agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility. In connection with the pending purchase of Fox Energy Company LLC, we will pay $50.0 million to terminate this tolling arrangement. See Note 4, “Agreement to Purchase Fox Energy Center,” for more information regarding this pending purchase. As of September 30, 2012, and December 31, 2011, we had 500 megawatts of capacity available under this agreement.

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 contracts compared with the remaining lives of the plants and the fact that we do not have the power to direct the operations and maintenance of the facilities, we determined we are not the primary beneficiary of this variable interest entity.

At September 30, 2012, and December 31, 2011, the assets and liabilities on the 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 this contract. There is not a significant potential exposure to loss as a result of our involvement with the variable interest entity.

NOTE 13—FAIR VALUE

Fair Value Measurements

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, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	1.2	$	—	$	—	$	1.2
Financial transmission rights (FTRs)	—		—		1.9		1.9
Petroleum products contracts	0.2		—		—		0.2
Total	$	1.4	$	—	$	1.9	$	3.3
Risk management liabilities
Natural gas contracts	$	0.2	$	—	$	—	$	0.2
FTRs	—		—		0.2		0.2
Coal contract	—		—		9.3		9.3
Total	$	0.2	$	—	$	9.5	$	9.7

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	December 31, 2011
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
FTRs	—		—		1.3		1.3
Petroleum products contracts	0.1		—		—		0.1
Total	$	0.2	$	—	$	1.3	$	1.5
Risk management liabilities
Natural gas contracts	$	2.5	$	—	$	—	$	2.5
FTRs	—		—		0.1		0.1
Coal contract	—		—		6.9		6.9
Total	$	2.5	$	—	$	7.0	$	9.5

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.

The risk management assets and liabilities listed in the tables above include NYMEX futures and options, as well as financial contracts used to manage transmission congestion costs in the MISO market. NYMEX contracts are valued using the NYMEX end-of-day settlement price, which is a Level 1 input. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input. The valuation for the physical coal contract is categorized in Level 3, as significant assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. For more information on our derivative instruments, see Note 3, “Risk Management Activities.”  There were no transfers between the levels of the fair value hierarchy during the three and nine months ended September 30, 2012, and 2011.

We have established a risk oversight committee 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 the trading function. 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. Corrections to the fair value inputs are made if necessary.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at September 30, 2012. 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 derivative to be classified as Level 3.

	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
FTRs	$	1.9	$	0.2	Market-based	Forward market prices ($/megawatt-month) (1)	96.63
Coal contract	—		$	9.3	Market-based	Forward market prices ($/ton) (2)	14.75 – 16.20

(1)Represents forward market prices developed using historical cleared pricing data from MISO used in the valuation of FTRs.

(2)Represents third-party forward market pricing used in the valuation of our coal contract.

Significant changes in historical settlement prices and forward coal prices would result in a directionally similar significant change in fair value.

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

	Three Months Ended September 30, 2012									Nine Months Ended September 30, 2012
(Millions)	FTRs			Coal Contract			Total			FTRs			Coal Contract			Total
Balance at the beginning of period	$	2.5		$	(9.8	)	$	(7.3	)	$	1.2		$	(6.9	)	$	(5.7	)
Net realized (losses) gains included in earnings	(0.6		)	—			(0.6		)	1.4			—			1.4
Net unrealized gains (losses) recorded as regulatory assets or liabilities	—			2.1			2.1			(0.3		)	1.5			1.2
Purchases	—			—			—			2.8			—			2.8
Sales	—			—			—			(0.1		)	—			(0.1		)
Settlements	(0.2		)	(1.6		)	(1.8		)	(3.3		)	(3.9		)	(7.2		)
Balance at the end of period	$	1.7		$	(9.3	)	$	(7.6	)	$	1.7		$	(9.3	)	$	(7.6	)

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	Three Months Ended September 30, 2011									Nine Months Ended September 30, 2011
(Millions)	FTRs			Coal Contract			Total			FTRs			Coal Contract			Total
Balance at the beginning of period	$	3.4		$	(4.3	)	$	(0.9	)	$	2.0		$	2.5		$	4.5
Net realized gains (losses) included in earnings	0.2			—			0.2			(1.1		)	—			(1.1		)
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(0.3		)	4.2			3.9			(0.9		)	(1.7		)	(2.6		)
Purchases	—			—			—			2.8			—			2.8
Sales	(0.1		)	—			(0.1		)	(0.2		)	—			(0.2		)
Settlements	(1.0		)	(0.4		)	(1.4		)	(0.4		)	(1.3		)	(1.7		)
Balance at the end of period	$	2.2		$	(0.5	)	$	1.7		$	2.2		$	(0.5	)	$	1.7

Unrealized gains and losses on FTRs and the coal contract are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on FTRs, as well as the related transmission congestion costs, are recorded in 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, 2012				December 31, 2011
(Millions)	Carrying Amount		Fair Value		Carrying  Amount		Fair Value
Long-term debt	$	721.4	$	820.6	$	721.3	$	816.7
Long-term debt to parent	7.4		8.5		7.9		9.2
Preferred stock	51.2		52.7		51.2		51.9

The fair values of long-term debt 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 such item approximates fair value.

NOTE 14—MISCELLANEOUS INCOME

Total miscellaneous income was as follows:

	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2012		2011		2012		2011
Earnings in equity-method investments	$	2.6	$	2.6	$	8.2	$	8.0
Key executive life insurance	—		0.1		1.0		1.1
Equity portion of AFUDC	0.7		0.2		1.5		0.4
Other	0.5		—		0.7		0.6
Total miscellaneous income	$	3.8	$	2.9	$	11.4	$	10.1

NOTE 15—REGULATORY ENVIRONMENT

Wisconsin

2013 Rates

On March 30, 2012, we filed an application with the PSCW to increase our retail electric and natural gas rates $85.1 million and $12.8 million, respectively, with rates proposed to be effective January 1, 2013. The filing included a request for a 10.30% return on common equity and a common equity ratio of 52.37% in our regulatory capital structure. On October 3, 2012, we filed a proposed settlement agreement with the PSCW reflecting the results of the PSCW staff audit and more current information. On October 24, 2012, the PSCW verbally approved the settlement agreement. The settlement agreement, updated as of November 2012 for changes in certain costs, includes a $28.5 million retail electric rate increase, which will be offset by the 2012 fuel refund. The settlement agreement reflects an estimated 2012 fuel refund of $19.2 million. Any difference between the actual 2012 fuel refund and the rate increase will be deferred for recovery in a future rate proceeding. As a result, there will be no change to customers’ 2013 retail electric rates. The updated agreement also includes a $0.9 million retail natural gas rate decrease. The updated settlement agreement reflects a

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10.30% return on common equity and a common equity ratio of 51.61% in our regulatory capital structure. Decoupling was approved on a pilot basis for 2013. The decoupling mechanism will be based on total rate case-approved margins, rather than being calculated on a per-customer basis. It will continue to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. In addition, we were 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 at September 30, 2012. The settlement agreement also authorized the recovery of direct CSAPR costs incurred through the end of 2012. As of September 30, 2012, we deferred $3.2 million of costs related to CSAPR. We expect a final written order from the PSCW before the end of 2012.

2012 Rates

On December 9, 2011, the PSCW issued a final written order, 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 exceed a 2% price variance from costs included in rates, they will be deferred for recovery or refund in a future rate proceeding. The rate order allows for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection, and reflects reduced contributions to the Focus on Energy Program. The rate order also allows for the deferral of direct Cross State Air Pollution Rule (CSAPR) compliance costs, including carrying costs.

2011 Rates

On January 13, 2011, the PSCW issued a final written order authorizing an electric rate increase of $21.0 million, calculated on a per-unit basis. Although the rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The rate order also included a projected increase in customer counts that did not materialize, which impacts the decoupling calculation as it adjusts for differences between the actual and authorized margin per customer. The $21.0 million electric rate increase included $20.0 million of recovery of prior deferrals, the majority of which related to the recovery of the 2009 electric decoupling deferral. The $21.0 million excluded the impact of a $15.2 million estimated fuel refund (including carrying costs) from 2010. The PSCW rate order also required an $8.3 million decrease in natural gas rates, which included $7.1 million of recovery for the 2009 decoupling deferral. The new rates were effective January 14, 2011, and reflected a 10.30% return on common equity, down from a 10.90% return on common equity in the previous rate order, and a common equity ratio of 51.65% in our regulatory capital structure.

The order also addressed the new Wisconsin electric fuel rule, which was finalized on March 1, 2011. The new fuel rule was effective retroactive to January 1, 2011. It requires the deferral of under or over-collections of fuel and purchased power costs that exceed a 2% price variance from the cost of fuel and purchased power included in rates. Under or over-collections deferred in the current year will be recovered or refunded in a future rate proceeding.

NOTE 16—SEGMENTS OF BUSINESS

At September 30, 2012, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are the regulated electric utility operations and the regulated natural gas utility operations. The other segment includes nonutility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC.

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The table below presents information related to our reportable segments:

	Regulated Utilities
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Three Months Ended September 30, 2012
External revenues	$	343.1		$	35.0		$	378.1		$	—	$	—		$	378.1
Intersegment revenues	—			4.4			4.4			0.3		(4.7		)	—
Depreciation and amortization expense	20.3			3.8			24.1			0.1		(0.1		)	24.1
Miscellaneous income	0.8			0.1			0.9			2.9		—			3.8
Interest expense	8.0			2.0			10.0			0.5		—			10.5
Provision (benefit) for income taxes	17.3			(3.8		)	13.5			0.9		—			14.4
Preferred stock dividend requirements	(0.6		)	(0.1		)	(0.7		)	—		—			(0.7		)
Net income (loss) attributed to common shareholder	43.9			(2.7		)	41.2			1.3		—			42.5
Three Months Ended September 30, 2011
External revenues	$	339.8		$	37.0		$	376.8		$	0.3	$	(0.3	)	$	376.8
Intersegment revenues	—			4.1			4.1			—		(4.1		)	—
Depreciation and amortization expense	20.1			3.7			23.8			0.2		(0.1		)	23.9
Miscellaneous income	0.2			0.1			0.3			2.6		—			2.9
Interest expense	8.5			2.0			10.5			0.6		—			11.1
Provision (benefit) for income taxes	23.5			(3.8		)	19.7			—		—			19.7
Preferred stock dividend requirements	(0.6		)	(0.1		)	(0.7		)	—		—			(0.7		)
Net income (loss) attributed to common shareholder	38.7			(6.3		)	32.4			2.2		—			34.6

	Regulated Utilities
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Nine Months Ended September 30, 2012
External revenues	$	922.6		$	197.2		$	1,119.8		$	—	$	—		$	1,119.8
Intersegment revenues	—			7.5			7.5			1.0		(8.5		)	—
Depreciation and amortization expense	60.5			11.4			71.9			0.5		(0.4		)	72.0
Miscellaneous income	1.4			0.1			1.5			9.9		—			11.4
Interest expense	24.4			5.9			30.3			1.6		—			31.9
Provision for income taxes	38.8			6.9			45.7			2.4		—			48.1
Preferred stock dividend requirements	(1.9		)	(0.4		)	(2.3		)	—		—			(2.3		)
Net income attributed to common shareholder	86.5			14.6			101.1			6.1		—			107.2
Nine Months Ended September 30, 2011
External revenues	$	923.0		$	246.6		$	1,169.6		$	1.0	$	(1.0	)	$	1,169.6
Intersegment revenues	—			8.8			8.8			—		(8.8		)	—
Depreciation and amortization expense	60.3			11.2			71.5			0.5		(0.4		)	71.6
Miscellaneous income	0.5			—			0.5			9.6		—			10.1
Interest expense	30.5			7.1			37.6			1.8		—			39.4
Provision for income taxes	43.7			8.4			52.1			2.8		—			54.9
Preferred stock dividend requirements	(1.9		)	(0.4		)	(2.3		)	—		—			(2.3		)
Net income attributed to common shareholder	78.2			12.2			90.4			5.3		—			95.7

NOTE 17—NEW ACCOUNTING PRONOUNCEMENTS

Recent Accounting Guidance Not Yet Effective

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities,” was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. This guidance is effective for our reporting period ending March 31, 2013. Adoption of this guidance will result in new disclosures in Note 3, “Risk Management Activities,” in the first quarter of 2013.

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ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment,” was issued in July 2012. The amendments give companies an option to first perform a qualitative assessment to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. If a company concludes that this is the case, the fair value of the indefinite-lived intangible asset must be determined, and a quantitative impairment test is required. Otherwise, a company can bypass the quantitative impairment test. This guidance is effective for our reporting period ending March 31, 2013, and is not expected to have a significant impact on our financial statements.

NOTE 18—RELATED PARTY TRANSACTIONS

We and our subsidiary, WPS Leasing, routinely enter into transactions with related parties, including Integrys Energy Group, its subsidiaries, and other entities in which we have material interests.

We provide repair and maintenance services to ATC under an Operation and Maintenance Services Agreement for Transmission Facilities approved by the PSCW. Services are billed to ATC under this agreement at our fully allocated cost.

The table below includes information related to transactions entered into with related parties as of:

(Millions)	September 30, 2012		December 31, 2011
Notes payable (1)
Integrys Energy Group	$	7.4	$	7.9
Benefit costs (2)
Receivables from related parties	—		13.0
Liability related to income tax allocation
Integrys Energy Group	7.5		8.0

(1)WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.

(2)The December 31, 2011 balance reflected the unrecognized pension costs that were allocated to Integrys Energy Group’s subsidiaries for the nonqualified retirement plan. At September 30, 2012, only the unrecognized pension costs associated with our past and current employees were reflected on our balance sheet.

In addition to the above transactions, $22.6 million was repaid to related parties during 2012 for amounts previously paid to us for the unfunded nonqualified retirement plan.

The following table shows activity associated with related party transactions:

	Three Months				Nine Months
	Ended September 30				Ended September 30
(Millions)	2012		2011		2012		2011
Electric transactions
Sales to UPPCO	$	6.1	$	6.3	$	17.1	$	17.3
Natural gas transactions
Sales to Integrys Energy Services	0.1		0.1		0.5		0.3
Purchases from Integrys Energy Services	0.1		0.3		0.5		0.7
Interest expense (1)
Integrys Energy Group	0.1		0.2		0.4		0.5
Transactions with equity method investees
Charges from ATC for network transmission services	23.5		24.2		70.6		72.5
Charges to ATC for services and construction	1.8		1.9		6.9		8.6
Net proceeds from WRPC sales of energy to MISO	0.6		1.3		2.4		4.0
Purchases of energy from WRPC	1.2		1.1		3.7		3.7
Revenues from services provided to WRPC	0.2		0.1		0.6		0.5
Income from WPS Investments, LLC (2)	2.5		2.5		7.6		7.3

(1)WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.

(2)WPS Investments, LLC is a consolidated subsidiary of Integrys Energy Group that is jointly owned by Integrys Energy Group, UPPCO, and us. At September 30, 2012, we had an 11.79% interest in WPS Investments accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys Energy Group to WPS Investments.

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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, 2011.

SUMMARY

We are a regulated electric and natural gas utility and a wholly owned subsidiary of Integrys Energy Group, Inc. We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers. We also provide wholesale electric service to numerous utilities and cooperatives for resale.

RESULTS OF OPERATIONS

Earnings Summary

	Three Months Ended						Change in		Nine Months Ended				Change in
	September 30						2012 Over		September 30				2012 Over
(Millions)	2012			2011			2011		2012		2011		2011
Electric utility operations	$	43.9		$	38.7		13.4	%	$	86.5	$	78.2	10.6	%
Natural gas utility operations	(2.7		)	(6.3		)	(57.1	)%	14.6		12.2		19.7	%
Other operations	1.3			2.2			(40.9	)%	6.1		5.3		15.1	%
Net income attributed to common shareholder	$	42.5		$	34.6		22.8	%	$	107.2	$	95.7	12.0	%

Third Quarter 2012 Compared with Third Quarter 2011

We recognized earnings of $42.5 million for the third quarter of 2012, compared with $34.6 million for the same quarter in 2011. This $7.9 million increase was driven by:

·A $5.9 million positive variance due to the 2012 reversal of deferred income taxes that had been expensed in prior years due to the implementation of federal health care reform. We were authorized recovery of this amount in our 2013 rate case settlement agreement.

·A $1.2 million after-tax increase in natural gas utility margins due to the rate order effective January 1, 2012, excluding the impact of the Focus on Energy program which is offset in operating expenses.

·A $0.9 million after-tax decrease in electric utility maintenance expense, primarily due to fewer storms in our service territories in 2012.

·A $0.5 million after-tax increase in natural gas utility margins due to variances related to sales volumes.

These increases in earnings were partially offset by a $1.0 million after-tax decrease in electric utility wholesale margins, driven by a decrease in sales volumes.

Nine Months 2012 Compared with Nine Months 2011

We recognized earnings of $107.2 million for the nine months ended September 30, 2012, compared with $95.7 million for the same period in 2011. This $11.5 million increase was driven by:

·A $7.5 million positive period-over-period impact related to federal health care reform, driven by the reversal in 2012 of $5.9 million of deferred income taxes that had been expensed in prior years due to the implementation of federal health care reform. We were authorized recovery of this amount in our 2013 rate case settlement agreement.

·A $4.5 million after-tax decrease in interest expense, driven by the repayment of long-term debt in 2011.

·A $2.0 million after-tax decrease in electric utility maintenance expense, primarily due to fewer planned outages at our generation plants during 2012.

These increases in earnings were partially offset by:

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·A $2.3 million after-tax decrease in electric utility margins due to the 2012 rate case re-opener, excluding the impact of the Focus on Energy program which is offset in operating expenses.

·A $2.0 million decrease in electric utility wholesale margins, driven by lower sales volumes.

Regulated Electric Utility Segment Operations

	Three Months Ended						Change in		Nine Months Ended						Change in
	September 30						2012 Over		September 30						2012 Over
(Millions, except degree days)	2012			2011			2011		2012			2011			2011
Revenues	$	343.1		$	339.8		1.0	%	$	922.6		$	923.0		—	%
Fuel and purchased power costs	156.3			146.4			6.8	%	412.1			397.3			3.7	%
Margins	186.8			193.4			(3.4	)%	510.5			525.7			(2.9	)%
Operating and maintenance expense	87.1			91.7			(5.0	)%	267.8			279.5			(4.2	)%
Depreciation and amortization expense	20.3			20.1			1.0	%	60.5			60.3			0.3	%
Taxes other than income taxes	10.4			10.5			(1.0	)%	32.0			32.1			(0.3	)%
Operating income	69.0			71.1			(3.0	)%	150.2			153.8			(2.3	)%
Miscellaneous income	0.8			0.2			300.0	%	1.4			0.5			180.0	%
Interest expense	(8.0		)	(8.5		)	(5.9	)%	(24.4		)	(30.5		)	(20.0	)%
Other expense	(7.2		)	(8.3		)	(13.3	)%	(23.0		)	(30.0		)	(23.3	)%
Income before taxes	$	61.8		$	62.8		(1.6	)%	$	127.2		$	123.8		2.7	%
Sales in kilowatt-hours
Residential	832.2			816.3			1.9	%	2,165.8			2,182.0			(0.7	)%
Commercial and industrial	2,116.7			2,135.9			(0.9	)%	6,077.0			6,023.2			0.9	%
Wholesale	1,587.5			1,247.2			27.3	%	3,837.2			3,415.2			12.4	%
Other	7.2			7.1			1.4	%	23.2			23.3			(0.4	)%
Total sales in kilowatt-hours	4,543.6			4,206.5			8.0	%	12,103.2			11,643.7			3.9	%
Weather
Heating degree days	252			246			2.4	%	3,864			5,222			(26.0	)%
Cooling degree days	514			494			4.0	%	789			596			32.4	%

Third Quarter 2012 Compared with Third Quarter 2011

Margins

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.

Electric utility segment margins decreased $6.6 million, driven by:

·An approximate $4 million decrease in margins due to impacts from our 2012 rate case re-opener. The PSCW approved a rate increase effective January 1, 2012. The rate increase was driven by anticipated increases in fuel and purchased power costs that did not materialize. Under the fuel rules, we deferred a portion of the difference between the costs included in rates and the actual fuel costs. This portion will be refunded to customers. Excluding the impact from fuel and purchased power costs, the 2012 rate case re-opener resulted in a rate decrease. The rate decrease was primarily driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions to the Focus on Energy Program was offset by lower operating expenses due to reduced payments to the program in 2012.

·An approximate $2 million decrease in wholesale margins, driven by a decrease in sales volumes. The decrease was primarily due to a reduction in sales to one large customer.

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·A $1 million net decrease in margins from residential and commercial and industrial customers due to variances related to sales volumes. An increase in margins from the quarter-over-quarter change in sales volumes was more than offset by the impact from the decoupling mechanism. Although decoupling was implemented to minimize the impact of changes in sales volumes, it does not cover all customers or jurisdictions.

·Margins increased approximately $1 million due to a 1.9% increase in sales volumes to residential customers.

·Margins decreased approximately $2 million due to our decoupling mechanism.

Operating Income

Operating income at the electric utility segment decreased $2.1 million. The decrease was due to the $6.6 million decrease in margins discussed above, partially offset by a $4.5 million decrease in operating expenses. The decrease in operating expenses was driven by:

·A $2.9 million decrease in customer assistance expense driven by reduced payments to the Focus on Energy Program. These payments are recovered in rates.

·A $1.5 million decrease in maintenance expense, primarily due to fewer storms in our service territories in 2012.

·A $0.7 million decrease in customer accounts expense driven by a decrease in maintenance costs related to our customer billing system.

·These decreases were partially offset by a $1.2 million increase in employee benefit related expenses. The increase was primarily due to the quarter-over-quarter change in the fair value of amounts owed to plan participants under deferred compensation plans.

Other Expense

Other expense decreased $1.1 million, driven by an increase in AFUDC, primarily related to environmental compliance projects at the Columbia plant. Also contributing to the decrease in other expense was a decrease in interest expense, driven by the maturity and repayment of $150.0 million of long-term debt in August 2011.

Nine Months 2012 Compared with Nine Months 2011

Margins

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.

Electric utility segment margins decreased $15.2 million, driven by:

·An approximate $12 million decrease in margins due to impacts from our 2012 rate case re-opener. The PSCW approved a rate increase effective January 1, 2012. The rate increase was driven by anticipated increases in fuel and purchased power costs that did not materialize. Under the fuel rules, we deferred a portion of the difference between the costs included in rates and the actual fuel costs. This portion will be refunded to customers. Excluding the impact from fuel and purchased power costs, the 2012 rate case re-opener resulted in a rate decrease. The rate decrease was primarily driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions to the Focus on Energy Program was offset by lower operating expenses due to reduced payments to the program in 2012.

·An approximate $3 million decrease in wholesale margins, driven by a decrease in sales volumes. The decrease was primarily due to a reduction in sales to one large customer.

·These decreases were partially offset by an approximate $1 million net increase in margins from residential and commercial and industrial customers due to variances related to sales volumes. The margin impact from the period-over-period change in sales volumes was more than offset by the impact from the decoupling mechanism. Although decoupling was implemented to minimize the impact of changes in sales volumes, it does not cover all customers or jurisdictions.

·A 0.7% decrease in sales volumes to residential customers, driven by warmer weather during the heating season, resulted in an approximate $1 million decrease in margins.

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·A 0.9% increase in sales volumes to commercial and industrial customers drove an approximate $1 million increase in margins.

·Margins increased approximately $1 million due to our decoupling mechanism.

Operating Income

Operating income at the electric utility segment decreased $3.6 million. The decrease was due to the $15.2 million decrease in margins discussed above, partially offset by an $11.6 million decrease in operating expenses. The decrease in operating expenses was driven by:

·An $8.6 million decrease in customer assistance expense driven by reduced payments to the Focus on Energy Program. These payments are recovered in rates.

·A $3.3 million decrease in maintenance expense, primarily due to fewer planned outages at our generation plants during 2012.

·A $1.2 million decrease in asset usage charges from IBS driven by certain computer hardware that was fully depreciated in 2011.

·A $1.1 million decrease in electric transmission expense.

·A $1.0 million decrease in customer accounts expense driven by a decrease in maintenance costs related to our customer billing system.

·These decreases were partially offset by a $4.0 million increase in employee benefit related expenses. The increase was primarily due to the period-over-period change in the fair value of amounts owed to plan participants under deferred compensation plans as well as an increase in postretirement medical expenses. Partially offsetting these increases was lower pension expense driven by an increase in contributions, which increased plan assets.

Other Expense

Other expense decreased $7.0 million, driven by a decrease in interest expense, primarily due to the maturity and repayment of $150.0 million of long-term debt in August 2011.

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Regulated Natural Gas Utility Segment Operations

	Three Months Ended						Change in		Nine Months Ended						Change in
	September 30						2012 Over		September 30						2012 Over
(Millions, except heating degree days)	2012			2011			2011		2012			2011			2011
Revenues	$	39.4		$	41.1		(4.1	)%	$	204.7		$	255.4		(19.9	)%
Natural gas purchased for resale	23.3			26.2			(11.1	)%	113.5			158.1			(28.2	)%
Margins	16.1			14.9			8.1	%	91.2			97.3			(6.3	)%
Operating and maintenance expense	15.6			18.0			(13.3	)%	48.2			54.1			(10.9	)%
Depreciation and amortization expense	3.8			3.7			2.7	%	11.4			11.2			1.8	%
Taxes other than income taxes	1.2			1.3			(7.7	)%	3.9			3.9			—	%
Operating income (loss)	(4.5		)	(8.1		)	(44.4	)%	27.7			28.1			(1.4	)%
Miscellaneous income	0.1			0.1			—	%	0.1			—			N/A
Interest expense	(2.0		)	(2.0		)	—	%	(5.9		)	(7.1		)	(16.9	)%
Other expense	(1.9		)	(1.9		)	—	%	(5.8		)	(7.1		)	(18.3	)%
Income (loss) before taxes	$	(6.4	)	$	(10.0	)	(36.0	)%	$	21.9		$	21.0		4.3	%
Retail throughput in therms
Residential	14.4			15.0			(4.0	)%	133.6			168.7			(20.8	)%
Commercial and industrial	11.8			11.8			—	%	80.0			98.2			(18.5	)%
Other	20.5			9.5			115.8	%	38.1			23.2			64.2	%
Total retail throughput in therms	46.7			36.3			28.7	%	251.7			290.1			(13.2	)%
Transport throughput in therms	67.8			68.4			(0.9	)%	243.2			252.9			(3.8	)%
Commercial and industrial
Total throughput in therms	114.5			104.7			9.4	%	494.9			543.0			(8.9	)%
Weather
Heating degree days	252			246			2.4	%	3,864			5,222			(26.0	)%

Third Quarter 2012 Compared with Third Quarter 2011

Margins

Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 31% decrease in the average per-unit cost of natural gas sold during the third quarter of 2012, which had no impact on margins.

Natural gas utility segment margins increased $1.2 million. The increase in margins was driven by decoupling accruals in 2011, which had a positive impact on the quarter-over-quarter variance. Decoupling lessened the positive impact in 2011 from some of the increased sales volumes through higher future refunds to customers.

Operating Loss

Operating loss at the natural gas utility segment decreased $3.6 million. This decrease was primarily driven by a $2.4 million decrease in operating and maintenance expenses and the $1.2 million increase in margins discussed above. The decrease in operating and maintenance expenses primarily related to a decrease in customer assistance expense, driven by reduced payments to the Focus on Energy Program. Costs for the program are recovered in rates.

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Nine Months 2012 Compared with Nine Months 2011

Margins

Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 17% decrease in the average per-unit cost of natural gas sold during 2012, which had no impact on margins.

Natural gas utility segment margins decreased $6.1 million, driven by:

·An approximate $3 million decrease in margins related to a reduction in rates in our rate order, effective January 1, 2012. The rate decrease was driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions is offset by lower operating and maintenance expenses. See Note 15, “Regulatory Environment,” for more information on this rate order.

·An approximate $3 million net decrease in margins, including the impact of decoupling, due to an 8.9% decrease in volumes sold.

·Substantially warmer weather during 2012 drove an approximate $14 million decrease in margins. Heating degree days decreased 26.0%.

·Lower sales volumes excluding the impact of weather resulted in an approximate $1 million decrease in margins. Sales volumes were lower due to lower use per residential and commercial and industrial customer.

·The decrease in margins due to lower volumes sold was partially offset by an approximate $12 million increase in decoupling recovery. During 2012, decoupling lessened the negative impact from some of the decreased sales volumes through higher future recoveries from customers. This was limited by an $8 million decoupling cap that was reached during the second quarter of 2012. During 2011, decoupling lessened the positive impact from some of the increased sales volumes through higher future refunds to customers. In addition, although decoupling was implemented to minimize the impact of changes in sales volumes, it does not cover all jurisdictions or customers.

Operating Income

Operating income at the natural gas utility segment decreased $0.4 million. This decrease was primarily driven by the $6.1 million decrease in margins discussed above, partially offset by a $5.9 million decrease in operating and maintenance expenses. The decrease in operating and maintenance expenses primarily related to a decrease in customer assistance expense, driven by reduced payments to the Focus on Energy Program. Costs for the program are recovered in rates.

Other Expense

Other expense decreased $1.3 million, driven by a decrease in interest expense, primarily due to the maturity and repayment of $150.0 million of long-term debt in August 2011.

Other Segment Operations

	Three Months Ended					Change in		Nine Months Ended				Change in
	September 30					2012 Over		September 30				2012 Over
(Millions)	2012			2011		2011		2012		2011		2011
Operating income (loss)	$	(0.2	)	$	0.2	N/A		$	0.2	$	0.3	(33.3	)%
Other income	2.4			2.0		20.0	%	8.3		7.8		6.4	%
Income before taxes	$	2.2		$	2.2	—	%	$	8.5	$	8.1	4.9	%

There was no material change in income before taxes for other segment operations for all periods presented.

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Provision for Income Taxes

	Three Months Ended September 30				Nine Months Ended September 30
	2012		2011		2012		2011
Effective Tax Rate	25.0	%	35.8	%	30.5	%	35.9	%

Third Quarter 2012 Compared with Third Quarter 2011

Our effective tax rate decreased in the third quarter of 2012. 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 our 2013 rate case settlement agreement. We 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 “Liquidity and Capital Resources, Other Future Considerations — Federal Health Care Reform” for more information.

Nine Months 2012 Compared with Nine Months 2011

Our effective tax rate decreased in 2012. The primary driver was a $5.9 million decrease in the provision for income taxes in 2012 as a result of our proposed 2013 rate case settlement agreement, as described above. The decrease was also partially related to an increase in our state income tax obligations in 2011, driven by a tax law change in Wisconsin. We recorded $1.6 million of income tax expense in 2011 when we increased our deferred income tax liabilities related to this tax law change.

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 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, 2012, net cash provided by operating activities was $210.5 million, compared with $191.4 million for the same period in 2011. The $19.1 million increase in net cash provided by operating activities was driven by:

·Net cash provided by working capital of $106.8 million during the nine months ended September 30, 2012, compared with $5.2 million of net cash used for working capital during the same period in 2011. The period-over-period change in working capital was primarily due to the following:

·A $49.2 million period-over-period decrease in prepaid taxes. This change was driven by higher tax refunds accrued in 2011, compared with 2012, primarily due to 100% bonus depreciation and increased tax deductions for pension funding in 2011. In addition, federal and state income tax refunds received  in 2012 significantly exceeded amounts received in 2011.

·A $10.2 million decrease in inventories during 2012, compared with a $32.1 million increase during 2011. The change is mainly due to decreased coal freight costs and declining natural gas prices in 2012.

·A $33.9 million positive impact from a $29.6 million increase in other current liabilities in 2012, compared with a $4.3 million decrease in 2011. The change was driven by an increase in 2012 in fuel and purchased power costs refundable to customers, versus a decrease in amounts refundable in 2011.

Partially offsetting the impact from the change in working capital was the following:

·A $47.9 million increase in contributions to pension and other postretirement benefit plans.

·A $22.6 million repayment of related party payables in 2012. Amounts previously paid to us for the unfunded nonqualified retirement plan were returned to related parties.

·A decrease in net income, adjusted for non-cash items.

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Investing Cash Flows

Net cash used for investing activities was $120.3 million during the nine months ended September 30, 2012, compared with $63.9 million for the same period in 2011. The $56.4 million increase in net cash used for investing activities was driven by an increase in cash used to fund capital expenditures (discussed below).

Capital Expenditures

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

Reportable Segment (millions)	2012		2011		Change
Electric utility	$	104.0	$	50.4	$	53.6
Natural gas utility	22.0		17.1		4.9
Other	—		0.3		(0.3		)
WPS consolidated	$	126.0	$	67.8	$	58.2

The increase in capital expenditures at the electric utility segment was primarily due to environmental compliance projects at the Columbia plant in 2012.

Financing Cash Flows

Net cash used for financing activities was $90.8 million during the nine months ended September 30, 2012, compared with $193.6 million for the same period in 2011. The $102.8 million decrease in net cash used for financing activities was driven by the following:

·A repayment of $150.0 million of long-term debt in 2011.

·Equity contributions from Integrys Energy Group of $40.0 million in 2012.

·A $25.0 million decrease in capital returns to Integrys Energy Group.

Partially offsetting these decreases in cash used for financing activities was a $119.7 million decrease in net borrowings of commercial paper.

Significant Financing Activities

For information on short-term debt, see Note 5, “Short-Term Debt and Lines of Credit.”

For information on long-term debt, see Note 6, “Long-Term Debt.”

Credit Ratings

We use internally generated funds and commercial paper borrowings to satisfy most of our capital requirements. We periodically issue long-term debt and receive equity contributions from Integrys Energy Group to reduce short-term debt, fund future growth, and maintain capitalization ratios as authorized by the PSCW.

Our current credit ratings are listed in the table below:

Credit Ratings	Standard & Poor’s		Moody’s
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
Credit facility		N/A		A2

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

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On January 24, 2012, Standard & Poor’s confirmed our “stable” outlook.

Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of September 30, 2012, including those of our subsidiary.

			Payments Due By Period
(Millions)	Total Amounts Committed		2012		2013 to 2014		2015 to 2016		2017 and Thereafter
Long-term debt principal and interest payments (1)	$	1,008.6	$	159.2	$	202.6	$	166.4	$	480.4
Operating lease obligations	18.7		0.3		2.6		1.3		14.5
Commodity purchase obligations (2)	1,477.0		95.1		443.1		179.9		758.9
Purchase orders (3)	201.7		200.4		1.3		—		—
Pension and other postretirement funding obligations (4)	192.6		13.3		124.8		42.7		11.8
Total contractual cash obligations	$	2,898.6	$	468.3	$	774.4	$	390.3	$	1,265.6

(1)Represents bonds and notes issued. We record all principal obligations on the balance sheet.

(2)The costs of commodity purchase obligations are expected to be recovered 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 payments related to the manufactured gas plant remediation liability of $69.8 million at September 30, 2012, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 8, “Commitments and Contingencies,” for more information about environmental liabilities. The table also does not reflect any payments for the September 30, 2012 liability of $0.5 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 7, “Income Taxes,” for more information on unrecognized tax benefits.

Capital Requirements

As of September 30, 2012, our capital expenditures for the three-year period 2012 through 2014 were expected to be as follows:

(Millions)
Acquisition of Fox Energy Center	$	390
Environmental projects	386
Electric and natural gas distribution projects	166
Electric and natural gas delivery and customer service projects	107
Other projects	130
Total capital expenditures	$	1,179

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, 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 2012 through 2014 primarily through internally generated funds (net of forecasted dividend payments), debt financings, and equity infusions from Integrys Energy Group. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth. We believe we have adequate financial flexibility and resources to meet our future needs.

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At September 30, 2012, we 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 5, “Short-Term Debt and Lines of Credit,” for more information on credit facilities and other short-term credit agreements. See Note 6, “Long-Term Debt,” for more information on long-term debt.

Other Future Considerations

Decoupling

Decoupling for natural gas and electric residential and small commercial and industrial customers was approved by the PSCW on a four-year trial basis for us, effective January 1, 2009, and ending on December 31, 2012. Decoupling allows us to adjust future rates to recover or refund a portion of the difference between the actual and authorized margin per customer impact of variations in volumes. The mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels, nor does it cover all customer classes. This decoupling mechanism includes an annual $14.0 million cap for electric service and 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 order. Decoupling was approved for 2013 on a pilot basis as part of the 2013 settlement agreement. The decoupling mechanism will be based on total rate case-approved margins, rather than being calculated on a per-customer basis. It will continue to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service.

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. On March 27, 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. The EPA planned to propose performance standards for existing units in 2011 and finalize them in 2012; however, that proposal has been delayed.

A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels. However, we believe the 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.

All of our generation and distribution facilities are located in the upper Midwest region of the United States. The same is true for all of our customers’ facilities. The physical risks 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.

Federal Health Care Reform

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (HCR) were signed into law. HCR contains various provisions that will affect the cost of providing health care coverage to our active and retired employees and their dependents. Although these provisions become effective at various times over 10 years, some provisions that affect the cost of providing benefits to retirees were reflected in our financial statements in 2010, 2011, and 2012. Many provisions of HCR were being challenged in the courts. On June 28, 2012, the U.S. Supreme Court upheld the law’s individual mandate and left the provisions that impacted employer-sponsored health plans in place. The ruling eliminates much of the uncertainty concerning the impact of the law on employers who sponsor health care plans. Since the law was enacted in 2010, we have worked to create a long-term strategy for the implementation of the law. With the Supreme Court’s decision, the implementation of this strategy continues. Our focus is on continued compliance with the law’s many mandates, avoidance or reduction of tax impacts, and cost management. We successfully participated in the Early Retiree Reinsurance Program through the third quarter of 2011. Following the submission of our fourth quarter 2011 claim, we were informed that the program fund had been depleted and, as such, we are not anticipating any future funding.

Beginning in 2013, a provision of HCR will eliminate the tax deduction for employer-paid postretirement prescription drug charges to the extent those charges will be offset by the receipt of a federal Medicare Part D subsidy. As a result, we eliminated $4.4 million of our deferred tax asset related to postretirement benefits in 2010. All of this flowed through to net income as a component of income tax expense in 2010. An additional $1.6 million was expensed in June 2011 for deferred income taxes related to a Wisconsin tax law change. In February 2012, we were authorized recovery for the portion related to our Michigan operations. As part of the 2013 settlement agreement, we were authorized recovery in Wisconsin for the remaining $5.9 million of income tax expense that relates to this tax law change. As a result, this amount was recorded as a regulatory asset at September 30, 2012.

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

The Dodd-Frank Act was signed into law in July 2010. Significant rulings essential to its framework are now beginning to become effective for certain companies. Since some of these final rules are being challenged in court, it is difficult to predict how they will ultimately affect us. Certain provisions of the Dodd-Frank Act relating to derivatives could increase capital and/or collateral requirements. We continue to monitor developments related to this act and their potential impacts on our future financial results. At this time, we are making the necessary changes to comply with the known rules.

Federal Tax Law Changes

In December 2010, President Obama signed into law The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. This act includes tax incentives, such as an extension and increase of bonus depreciation, the extension of the research and experimentation credit, and the extension of treasury grants in lieu of claiming the investment tax credit or production tax credit for certain renewable energy investments. In September 2010, President Obama signed into law the Small Business Jobs Act of 2010. This act includes tax incentives that affect us, such as an extension to bonus depreciation and changes to listed property. We anticipate that these tax law changes will likely result in approximately $40.0 million of reduced cash payments for taxes through 2012. These tax incentives may also reduce our utility rate base and, thus, future earnings relative to prior expectations. We have primarily used the proceeds from these incentives to make incremental contributions to our various employee benefit plans. In addition, these tax incentives have helped reduce our financing needs.

In December 2011, the National Defense Authorization Act (NDAA) was enacted. The most relevant provision of the NDAA was to retroactively eliminate the application of the tax normalization rule for cash grants taken by a regulated utility in lieu of the investment tax credit or production tax credits. Prior to the enactment of NDAA, a regulated utility would have been required to amortize the grant in rates over the regulatory life of the renewable energy generating plant. Further, the allowed rate base on the generating plant could not be reduced by the unamortized grant balance during the life of the plant. As a result of the enactment of NDAA, we submitted an application to the U.S. Department of the Treasury in the third quarter of 2012 for a cash grant for our Crane Creek wind project. If the amount of the cash grant awarded is acceptable and if regulatory treatment provided by the PSCW, the MPSC, and the FERC is acceptable, it is likely we will proceed with taking a grant in lieu of production tax credits for Crane Creek. Due to the effects of regulation, we do not anticipate a significant financial impact if this change is made.

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, 2011, are still current and that there have been no significant changes.

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Item 3.Quantitative and Qualitative Disclosures About Market Risk

Our market risks have not changed materially from the market risks reported in our 2011 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 WPS’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 WPS’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, 2012, 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 8, “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 2011 Annual Report on Form 10-K, which was filed with the SEC on February 29, 2012.

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

Dividend Restrictions

Integrys Energy Group is the sole holder of our common stock; therefore, there is no established public trading market for our common stock. For information on dividends paid and dividend restrictions, see Note 11, “Common Equity.”

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, Wisconsin Public Service Corporation, has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Wisconsin Public Service Corporation
Date:  November 5, 2012	/s/ Linda M. Kallas
	Linda M. Kallas
	Vice President and Corporate Controller
	(Duly Authorized Officer and Chief Accounting Officer)

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WISCONSIN PUBLIC SERVICE CORPORATION

EXHIBIT INDEX TO FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2012

Exhibit No.	Description
2 + #	Purchase and Sale Agreement among Wisconsin Public Service Corporation, Fox Energy OP, L.P., and Fox River Power, LLC, dated as of September 28, 2012.
12	Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements
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 Wisconsin Public Service Corporation
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 Wisconsin Public Service Corporation
32	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation
101 *	Financial statements from the Quarterly Report on Form 10-Q of Wisconsin Public Service Corporation for the quarter ended September 30, 2012, filed on November 6, 2012, formatted in eXtensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Capitalization, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Notes To Financial Statements, and (vi) document and entity information

+	Schedules and exhibits to this document are not filed herewith. The Registrant agrees to furnish supplementally a copy of any such schedule or exhibit to the SEC upon request.
#	Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the SEC pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934, as amended. The redacted material was filed separately with the SEC.
*	In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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