UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2013

OR

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

For the transition period from __________ to __________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-3016	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 [ ]

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

Yes [X]    No [ ]

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

Large accelerated filer [ ]            Accelerated filer [ ]

Non-accelerated filer [X]            Smaller reporting company [ ]

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

Yes [ ]    No [X]

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

Common stock, $4 par value,

23,896,962 shares outstanding at

November 4, 2013

WISCONSIN PUBLIC SERVICE CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2013

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			6
			Page
	Note 1	Financial Information	6
	Note 2	Cash and Cash Equivalents	6
	Note 3	Risk Management Activities	6
	Note 4	Acquisition of Fox Energy Center	8
	Note 5	Goodwill and Other Intangible Assets	9
	Note 6	Short-Term Debt and Lines of Credit	9
	Note 7	Long-Term Debt	9
	Note 8	Income Taxes	10
	Note 9	Commitments and Contingencies	10
	Note 10	Employee Benefit Plans	13
	Note 11	Stock-Based Compensation	13
	Note 12	Common Equity	15
	Note 13	Variable Interest Entities	16
	Note 14	Fair Value	16
	Note 15	Miscellaneous Income	18
	Note 16	Regulatory Environment	19
	Note 17	Segments of Business	19
	Note 18	New Accounting Pronouncements	21
	Note 19	Related Party Transactions	21
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			32
ITEM 4.	Controls and Procedures			33
PART II.	OTHER INFORMATION			34
ITEM 1.	Legal Proceedings			34
ITEM 1A.	Risk Factors			34
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			34
ITEM 5.	Other Information			34
ITEM 6.	Exhibits			34
Signature				35
EXHIBIT INDEX				36

i

Acronyms Used in this Quarterly Report on Form 10-Q

AFUDC	Allowance for Funds Used During Construction
ATC	American Transmission Company LLC
EPA	United States Environmental Protection Agency
GAAP	United States Generally Accepted Accounting Principles
IRS	United States Internal Revenue Service
MISO	Midcontinent Independent System Operator, Inc.
MPSC	Michigan Public Service Commission
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. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.

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

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

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

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

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

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

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	Three Months Ended						Nine Months Ended
	September 30						September 30
(Millions)	2013			2012			2013			2012
Operating revenues	$	371.9		$	378.1		$	1,173.1		$	1,119.8
Cost of fuel, natural gas, and purchased power	151.3			175.0			528.2			517.4
Operating and maintenance expense	115.9			103.0			340.1			316.3
Depreciation and amortization expense	27.6			24.1			78.8			72.0
Taxes other than income taxes	11.9			11.7			36.5			36.0
Operating income	65.2			64.3			189.5			178.1
Miscellaneous income	6.0			3.8			16.9			11.4
Interest expense	10.7			10.5			31.9			31.9
Other expense	(4.7		)	(6.7		)	(15.0		)	(20.5		)
Income before taxes	60.5			57.6			174.5			157.6
Provision for income taxes	22.8			14.4			64.7			48.1
Net income	37.7			43.2			109.8			109.5
Preferred stock dividend requirements	(0.7		)	(0.7		)	(2.3		)	(2.3		)
Net income attributed to common shareholder	$	37.0		$	42.5		$	107.5		$	107.2

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)	2013		2012
Assets
Cash and cash equivalents	$	6.4	$	6.5
Accounts receivable and accrued unbilled revenues, net of reserves of $3.2 and $2.5, respectively	160.7		258.3
Receivables from related parties	4.7		5.0
Inventories
Fuel and gas	78.2		76.3
Materials and supplies, at average cost	34.8		33.3
Regulatory assets	25.5		26.1
Prepaid taxes	69.1		84.7
Other current assets	13.2		13.3
Current assets	392.6		503.5
Property, plant, and equipment, net of accumulated depreciation of $1,477.5 and $1,336.0, respectively	2,834.6		2,353.0
Regulatory assets	550.7		536.2
Goodwill	36.4		36.4
Other long-term assets	129.6		92.8
Total assets	$	3,943.9	$	3,521.9
Liabilities and Shareholders’ Equity
Short-term debt	$	314.4	$	95.4
Current portion of long-term debt	125.0		147.0
Accounts payable	108.5		131.0
Payables to related parties	16.3		13.5
Regulatory liabilities	23.4		27.6
Other current liabilities	73.1		61.8
Current liabilities	660.7		476.3
Long-term debt to parent	6.6		7.2
Long-term debt	724.5		724.4
Deferred income taxes	599.0		539.0
Deferred investment tax credits	8.2		8.5
Regulatory liabilities	288.8		281.0
Environmental remediation liabilities	64.9		68.8
Pension and other postretirement benefit obligations	145.5		164.6
Payables to related parties	6.2		6.7
Other long-term liabilities	73.5		72.7
Long-term liabilities	1,917.2		1,872.9
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	723.0		555.4
Retained earnings	496.2		470.5
Total liabilities and shareholders’ equity	$	3,943.9	$	3,521.9

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)				2013			2012
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				723.0			555.4
Retained earnings				496.2			470.5
Total common stock equity				1,314.8			1,121.5
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			511,882	51.2			51.2
Long-term debt to parent
	Series		Year Due
	8.76	%	2015	2.5			2.8
	7.35	%	2016	4.1			4.4
Total long-term debt to parent				6.6			7.2
Long-term debt
First Mortgage Bonds
	Series		Year Due
	7.125	%	2023	0.1			0.1
Senior Notes
	Series		Year Due
	3.95	%	2013	—			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
	3.671	%	2042	300.0			300.0
Total First Mortgage Bonds and Senior Notes				850.1			872.1
Unamortized discount on long-term debt				(0.6		)	(0.7		)
Total				849.5			871.4
Current portion of long-term debt				(125.0		)	(147.0		)
Total long-term debt				724.5			724.4
Total capitalization				$	2,097.1		$	1,904.3

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

4

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(Millions)	2013			2012
Operating Activities
Net income	$	109.8		$	109.5
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	78.8			72.0
Recoveries and refunds of regulatory assets and liabilities	(9.9		)	11.4
Bad debt expense	3.4			4.1
Pension and other postretirement expense	16.9			14.3
Pension and other postretirement contributions	(38.1		)	(109.5		)
Deferred income taxes and investment tax credits	60.3			23.4
Repayment of related party payable	—			(22.6		)
Equity income, net of dividends	(1.2		)	(0.8		)
Termination of tolling agreement with Fox Energy Company LLC	(50.0		)	—
Other	2.3			1.9
Changes in working capital
Collateral on deposit	0.8			(0.4		)
Accounts receivable and accrued unbilled revenues	25.5			31.3
Inventories	0.9			10.2
Prepaid taxes	15.6			50.4
Other current assets	2.0			(1.8		)
Accounts payable	(27.5		)	(12.5		)
Other current liabilities	22.7			29.6
Net cash provided by operating activities	212.3			210.5
Investing Activities
Capital expenditures	(172.8		)	(126.0		)
Proceeds from the sale or disposal of assets	1.4			2.3
Acquisition of Fox Energy Company LLC	(391.6		)	—
Grant received related to Crane Creek Wind Project	69.0			—
Other	2.7			3.4
Net cash used for investing activities	(491.3		)	(120.3		)
Financing Activities
Short-term debt, net	19.0			0.6
Borrowing on term credit facility	200.0			—
Repayment of long-term debt	(22.0		)	—
Repayment of long-term debt to parent	(0.6		)	(0.5		)
Payment of dividends to parent	(81.5		)	(79.1		)
Equity contribution from parent	200.0			40.0
Return of capital to parent	(35.0		)	(50.0		)
Preferred stock dividend requirements	(2.3		)	(2.3		)
Other	1.3			0.5
Net cash provided by (used for) financing activities	278.9			(90.8		)
Net change in cash and cash equivalents	(0.1		)	(0.6		)
Cash and cash equivalents at beginning of period	6.5			5.5
Cash and cash equivalents at end of period	$	6.4		$	4.9

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

5

WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY

CONDENSED NOTES TO FINANCIAL STATEMENTS (Unaudited)

September 30, 2013

NOTE 1 — FINANCIAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated 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, 2012. Financial results for an interim period may not give a true indication of results for the year.

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

NOTE 2 — CASH AND CASH EQUIVALENTS

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

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

	Nine Months Ended September 30
(Millions)	2013			2012
Cash paid for interest	$	22.7		$	20.8
Cash received for income taxes	(2.4		)	(14.2		)

Cash received from income taxes decreased $11.8 million, primarily driven by refunds received in 2012 due to changes in estimated payments made for the prior year.

Construction costs funded through accounts payable totaled $29.5 million at September 30, 2013, and $15.8 million at September 30, 2012. 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.

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

		September 30, 2013
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	0.3	$	0.2
FTRs	Other Current	2.2		0.4
Petroleum product contracts	Other Current	—		0.1
Coal contracts	Other Current	—		2.6
Coal contracts	Other Long-term	1.5		0.1
	Other Current	2.5		3.3
	Other Long-term	1.5		0.1
Total		$	4.0	$	3.4

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

6

		December 31, 2012
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	0.1	$	0.6
FTRs	Other Current	1.2		0.1
Petroleum product contracts	Other Current	0.1		—
Coal contracts	Other Current	0.3		4.7
Coal contracts	Other Long-term	2.2		4.3
	Other Current	1.7		5.4
	Other Long-term	2.2		4.3
Total		$	3.9	$	9.7

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

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

	September 30, 2013
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	2.5	$	0.6	$	1.9
Derivative assets not subject to master netting or similar arrangements	1.5				1.5
Total risk management assets	$	4.0			$	3.4
Derivative liabilities subject to master netting or similar arrangements	$	0.7	$	0.6	$	0.1
Derivative liabilities not subject to master netting or similar arrangements	2.7				2.7
Total risk management liabilities	$	3.4			$	2.8

	December 31, 2012
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	1.4	$	0.2	$	1.2
Derivative assets not subject to master netting or similar arrangements	2.5				2.5
Total risk management assets	$	3.9			$	3.7
Derivative liabilities subject to master netting or similar arrangements	$	0.7	$	0.7	$	—
Derivative liabilities not subject to master netting or similar arrangements	9.0				9.0
Total risk management liabilities	$	9.7			$	9.0

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

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

(Millions)	September 30, 2013		December 31, 2012
Cash collateral provided to others related to contracts under master netting or similar arrangements *	$	3.5	$	4.3

*   Reflected in other current assets on the balance sheets.

7

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

		Three Months Ended September 30						Nine Months Ended September 30
(Millions)	Financial Statement Presentation	2013			2012			2013			2012
Natural gas	Balance Sheet — Regulatory assets (current)	$	(0.2	)	$	0.3		$	0.3		$	2.8
Natural gas	Balance Sheet — Regulatory liabilities (current)	—			0.3			(0.1		)	0.6
Natural gas	Balance Sheet — Regulatory liabilities (long-term)	—			0.1			—			0.1
Natural gas	Income Statement — Cost of fuel, natural gas, and purchased power	—			0.1			—			0.2
FTRs	Balance Sheet — Regulatory assets (current)	0.8			—			—			(0.6		)
FTRs	Balance Sheet — Regulatory liabilities (current)	—			—			(0.3		)	0.3
Petroleum	Balance Sheet — Regulatory assets (current)	0.1			0.2			—			0.1
Petroleum	Balance Sheet — Regulatory liabilities (current)	—			0.1			—			0.1
Petroleum	Income Statement — Operating and maintenance expense	(0.1		)	—			(0.1		)	—
Coal	Balance Sheet — Regulatory assets (current)	(0.6		)	0.7			2.1			(2.5		)
Coal	Balance Sheet — Regulatory assets (long-term)	0.2			(0.1		)	4.2			0.1
Coal	Balance Sheet — Regulatory liabilities (current)	—			—			(0.3		)	—
Coal	Balance Sheet — Regulatory liabilities (long-term)	1.5			—			(0.7		)	—

We had the following notional volumes of outstanding derivative contracts:

	September 30, 2013			December 31, 2012
Commodity	Purchases	Sales	Other  Transactions	Purchases	Other Transactions
Natural gas (millions of therms)	200.2	—	N/A	86.1	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	5,524.8	N/A	3,838.2
Petroleum products (barrels)	36,803.0	9,000.0	N/A	33,002.0	N/A
Coal contract (millions of tons)	5.1	N/A	N/A	5.1	N/A

NOTE 4 — ACQUISITION OF FOX ENERGY CENTER

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

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

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

(Millions)
Assets acquired (1)
Inventories - materials and supplies	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets (2)	15.6
Total assets acquired	$	393.4
Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8

⁽¹⁾  Relates to the electric utility segment.

⁽²⁾  Intangible assets recorded for contractual services agreements. See Note 5, "Goodwill and Other Intangible Assets," for more information.

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

The purchase was financed with a combination of short-term debt, cash provided by operations, and an equity contribution from our parent, Integrys Energy Group, Inc. We intend to replace the short-term debt in the fourth quarter of 2013 with long-term financing.

8

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

NOTE 5 — GOODWILL AND OTHER INTANGIBLE ASSETS

We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2013, and 2012. In the second quarter of 2013, we completed our annual goodwill impairment test, and no impairment resulted from this test.

Our intangible assets consist of contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. These contractual service agreements are included in other long-term assets on the balance sheet. At September 30, 2013, the gross carrying amount, accumulated amortization, and net carrying amount of these intangibles were $15.6 million, $1.2 million, and $14.4 million, respectively. The remaining amortization period at September 30, 2013, was approximately seven years. Amortization expense recorded as a component of depreciation and amortization expense in the statements of income for the three and nine months ended September 30, 2013, was $0.6 million and $1.2 million, respectively.

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

	For the Year Ending December 31
(Millions)	2013		2014		2015		2016		2017
Amortization to be recorded in depreciation and amortization expense	$	1.8	$	2.2	$	2.2	$	2.2	$	2.2

NOTE 6 — SHORT-TERM DEBT AND LINES OF CREDIT

Our outstanding short-term borrowings were as follows:

(Millions, except percentages)	September 30, 2013			December 31, 2012
Commercial paper	$	114.4		$	95.4
Average discount rate on commercial paper	0.15		%	0.24		%
Loan under term credit facility	$	200.0		$	—
Average interest rate on loan under term credit facility	0.78		%	—

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2013, and 2012, was $88.4 million and $156.3 million, respectively.

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

(Millions)	Maturity	September 30, 2013		December 31, 2012
Revolving credit facility	05/17/2014	$	135.0	$	135.0
Revolving credit facility	06/13/2017	115.0		115.0
Term credit facility	12/31/2013	200.0		—
Total short-term credit capacity		$	450.0	$	250.0
Less:
Loan outstanding under term credit facility		$	200.0	$	—
Commercial paper outstanding		114.4		95.4
Available capacity under existing agreements		$	135.6	$	154.6

The loan outstanding under our term credit facility relates to the purchase of Fox Energy Company LLC and must be repaid upon the earlier of our issuance of replacement long-term debt or December 31, 2013. See Note 4, "Acquisition of Fox Energy Center," for more information. The commercial paper outstanding at September 30, 2013, had maturity dates ranging from October 1, 2013, through October 22, 2013.

NOTE 7 — LONG-TERM DEBT

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

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In February 2013, our $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.

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

NOTE 8 — 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
	2013		2012		2013		2012
Effective Tax Rate	37.7	%	25.0	%	37.1	%	30.5	%

Our effective tax rate normally differs from the federal statutory tax 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 lower than the federal statutory tax rate of 35%. These differences were partially due to 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 16, "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.

During the three and nine months ended September 30, 2013, there was not a significant change in our liability for unrecognized tax benefits.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

(a) Unconditional 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 following table shows our minimum future commitments related to these purchase obligations as of September 30, 2013.

				Payments Due By Period
(Millions)	Date Contracts Extend Through	Total Amounts Committed		2013		2014		2015		2016		2017		Later Years
Electric utility
Purchased power	2029	$	783.8	$	35.7	$	61.3	$	32.0	$	28.2	$	27.0	$	599.6
Coal supply and transportation	2018	110.6		17.3		44.4		31.9		9.5		6.0		1.5
Natural gas utility supply and transportation	2024	281.8		12.6		46.6		43.3		39.5		38.4		101.4
Total		$	1,176.2	$	65.6	$	152.3	$	107.2	$	77.2	$	71.4	$	702.5

We also had commitments of $365.0 million in the form of purchase orders issued to various vendors at September 30, 2013, that relate to normal business operations, including construction projects.

(b) Environmental Matters

Air Permitting Violation Claims

Weston and Pulliam Clean Air Act (CAA) Issues:

In November 2009, the EPA issued a Notice of Violation (NOV) to us 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. We reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes:

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

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

• limitations on plant emissions,

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

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• a civil penalty of $1.2 million.

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

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

In May 2010, we received from the Sierra Club a Notice of Intent 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 in October 2012, but no further action has been taken by the Sierra Club as of September 30, 2013. It is unknown whether the Sierra Club will take further action in the future.

Columbia and Edgewater CAA Issues:

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

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

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

• limitations on plant emissions,

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

• our portion of a civil penalty and legal fees totaling $0.4 million.

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

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

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

Weston Title V Air Permit:

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

Columbia Title V Air Permit:

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

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

Weston 4 Construction Permit

From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits. In July 2010, 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 to resolve this issue as part of the current Title V air permit issued in July 2013 and subsequent proceedings discussed above. We do not expect this matter to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin's mercury rule requires a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of September 30, 2013, we estimate capital costs of approximately $9 million for our wholly owned plants to achieve the required reductions. The capital costs are expected to be recovered in future rates.

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

Sulfur Dioxide and Nitrogen Oxide:

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

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

Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether we will have 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, 2013, we estimated and accrued for $64.9 million of future undiscounted investigation and cleanup costs for all sites. We may adjust

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these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of September 30, 2013, cash expenditures for environmental remediation not yet recovered in rates were $13.0 million. We recorded a regulatory asset of $77.9 million at September 30, 2013, which is net of insurance recoveries received of $25.8 million, related to the expected recovery through rates of both cash expenditures and estimated future expenditures. 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 PSCW or the MPSC with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

NOTE 10 — EMPLOYEE BENEFIT PLANS

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

	Pension Benefits												Other Postretirement Benefits
	Three Months Ended September 30						Nine Months Ended September 30						Three Months Ended September 30						Nine Months Ended September 30
(Millions)	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	2.7		$	3.2		$	8.1		$	9.6		$	2.6		$	2.1		$	7.9		$	6.4
Interest cost	7.6			8.5			22.9			25.5			3.4			3.8			10.1			11.3
Expected return on plan assets	(14.3		)	(13.8		)	(42.9		)	(41.5		)	(3.7		)	(3.6		)	(11.1		)	(10.9		)
Amortization of transition obligation	—			—			—			—			—			0.1			—			0.2
Amortization of prior service cost (credit)	0.9			1.1			2.7			3.4			(0.6		)	(0.8		)	(1.6		)	(2.3		)
Amortization of net actuarial loss	6.0			3.7			18.0			11.1			1.9			1.4			5.6			4.2
Net periodic benefit cost	$	2.9		$	2.7		$	8.8		$	8.1		$	3.6		$	3.0		$	10.9		$	8.9

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. During the nine months ended September 30, 2013, we contributed $38.0 million to our pension plans and $0.1 million to our other postretirement benefit plans. We expect to contribute an additional $0.8 million to our pension plans and $15.6 million to our other postretirement benefit plans during the remainder of 2013, dependent upon various factors affecting us, including our liquidity position and tax law changes.

NOTE 11 — 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)	2013		2012		2013		2012
Stock options	$	0.2	$	0.2	$	0.5	$	0.4
Performance stock rights	0.4		0.1		1.7		1.8
Restricted share units	0.8		0.8		2.6		2.7
Total stock-based compensation expense	$	1.4	$	1.1	$	4.8	$	4.9
Deferred income tax benefit	$	0.6	$	0.4	$	1.9	$	2.0

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

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Stock Options

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

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

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

	Stock Options		Weighted-Average  Exercise Price Per  Share		Weighted-Average  Remaining Contractual Life (in Years)	Aggregate  Intrinsic Value (Millions)
Outstanding at December 31, 2012	66,852		$	49.95
Granted	19,364		56.00
Exercised	(33,473	)	49.28
Outstanding at September 30, 2013	52,743		$	52.60	7.2	$	0.2
Exercisable at September 30, 2013	15,291		$	51.49	4.0	$	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 on September 30, 2013. This is calculated as the difference between Integrys Energy Group’s closing stock price on September 30, 2013, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the nine months ended September 30, 2013, and 2012, was not significant.

As of September 30, 2013, 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 are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected volatility is estimated using two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at September 30:

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

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

	Performance Stock Rights		Weighted-Average Fair Value (2)
Outstanding at December 31, 2012	4,908		$	66.95
Granted	1,374		48.50
Award modifications (1)	2,601		39.80
Distributed	(4,318	)	74.53
Adjustment for final payout	996		74.53
Outstanding at September 30, 2013	5,561		$	45.16

⁽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.

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

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

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

	Performance Stock Rights
Outstanding at December 31, 2012	6,774
Granted	5,489
Award modifications *	(2,601	)
Distributed	(573	)
Adjustment for final payout	133
Outstanding at September 30, 2013	9,222

* 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, 2013, was $48.91 per performance stock right.

As of September 30, 2013, 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, 2013, and 2012, was not significant.

Restricted Share Units

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

	Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2012	67,954		$	48.26
Granted	23,055		56.05
Dividend equivalents	2,304		52.02
Vested and released	(28,079	)	46.20
Outstanding at September 30, 2013	65,234		$	52.04

As of September 30, 2013, $1.4 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.3 years.

The total intrinsic value of restricted share unit awards vested and released during the nine months ended September 30, 2013, and 2012, was $1.6 million and $1.5 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the nine months ended September 30, 2013, and 2012, was not significant.

The weighted-average grant date fair value of restricted share units awarded during the nine months ended September 30, 2013, and 2012, was $56.05 and $53.24 per unit, respectively.

NOTE 12 — 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 51% 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 shareholders and to provisions in our restated articles of

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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, 2013, total restricted net assets were $1,313.2 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $28.9 million at September 30, 2013.

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, 2013, we received $200.0 million of equity contributions from Integrys Energy Group, paid common stock dividends of $81.5 million to Integrys Energy Group, and returned $35.0 million of capital to Integrys Energy Group.

NOTE 13 — VARIABLE INTEREST ENTITIES

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

NOTE 14 — FAIR VALUE

Fair Value Measurements

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

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

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

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

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

Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

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

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

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

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the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.

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

	September 30, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.3	$	—	$	—	$	0.3
Financial transmission rights (FTRs)	—		—		2.2		2.2
Coal contracts	—		—		1.5		1.5
Total	$	0.3	$	—	$	3.7	$	4.0
Risk management liabilities
Natural gas contracts	$	0.2	$	—	$	—	$	0.2
FTRs	—		—		0.4		0.4
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		2.7		2.7
Total	$	0.3	$	—	$	3.1	$	3.4

	December 31, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
FTRs	—		—		1.2		1.2
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		2.5		2.5
Total	$	0.2	$	—	$	3.7	$	3.9
Risk management liabilities
Natural gas contracts	$	0.6	$	—	$	—	$	0.6
FTRs	—		—		0.1		0.1
Coal contracts	—		—		9.0		9.0
Total	$	0.6	$	—	$	9.1	$	9.7

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 physical coal contracts categorized in Level 3 is based on significant assumptions 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 or nine months ended September 30, 2013, and 2012.

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

	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
FTRs	$	2.2	$	0.4	Market-based	Forward market prices ($/megawatt-month) (1)	$116.47
Coal contract	1.5		2.7		Market-based	Forward market prices ($/ton) (2)	$12.21 - $14.63

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

⁽²⁾  Represents third-party forward market pricing.

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

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

	Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
(Millions)	FTRs			Coal Contracts			Total			FTRs			Coal Contracts			Total
Balance at the beginning of period	$	2.1		$	(2.3	)	$	(0.2	)	$	1.1		$	(6.5	)	$	(5.4	)
Net realized gains included in earnings	1.5			—			1.5			2.5			—			2.5
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0.8			(4.5		)	(3.7		)	(0.3		)	2.2			1.9
Purchases	—			—			—			3.2			—			3.2
Sales	—			—			—			(0.1		)	—			(0.1		)
Settlements	(2.6		)	5.6			3.0			(4.6		)	3.1			(1.5		)
Balance at the end of period	$	1.8		$	(1.2	)	$	0.6		$	1.8		$	(1.2	)	$	0.6

	Three Months Ended September 30, 2012									Nine Months Ended September 30, 2012
(Millions)	FTRs			Coal Contracts			Total			FTRs			Coal Contracts			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	)

Unrealized gains and losses on FTRs and coal contracts 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, 2013				December 31, 2012
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	849.5	$	858.4	$	871.4	$	966.2
Long-term debt to parent	6.6		7.2		7.2		8.2
Preferred stock	51.2		61.8		51.2		52.8

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 15 — MISCELLANEOUS INCOME

Total miscellaneous income was as follows:

	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2013		2012		2013		2012
Earnings from equity-method investments	$	2.8	$	2.6	$	8.6	$	8.2
Equity portion of AFUDC	2.9		0.7		6.6		1.5
Key executive life insurance for retired employees	0.1		—		1.0		1.0
Other	0.2		0.5		0.7		0.7
Total miscellaneous income	$	6.0	$	3.8	$	16.9	$	11.4

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NOTE 16 — REGULATORY ENVIRONMENT

Wisconsin

2014 Rate Case

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

In August 2013, the PSCW Staff submitted testimony and recommended rate increases of $9.3 million and $7.8 million for retail electric and natural gas, respectively, reflecting a 10.20% return on common equity. Their recommendation also included a common equity ratio of 50.14% in our regulatory capital structure. The PSCW held both technical and public hearings in September 2013. In October 2013, we issued an initial brief revising our requested retail electric and natural gas rate increases to approximately $60 million and approximately $14 million, respectively, including a reduced return on common equity of 10.60%. Included in these revised amounts, is our request for recovery of $1.7 million for the Wisconsin retail allocation of environmental remediation capital and operating costs related to our Consent Decree with the EPA. See Note 9, "Commitments and Contingencies," for more information. Finally, we requested the removal of the annual caps associated with the decoupling mechanism that is currently in place. Our revised request is a result of our current position on contested issues. New rates are expected to be effective January 1, 2014.

2013 Rates

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

A new decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism is based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism does not cover all customer classes, and it continues to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate proceeding.

2012 Rates

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

NOTE 17 — SEGMENTS OF BUSINESS

At September 30, 2013, 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, 2013
External revenues	$	331.7		$	40.2		$	371.9		$	—	$	—		$	371.9
Intersegment revenues	—			4.1			4.1			0.5		(4.6		)	—
Depreciation and amortization expense	23.6			3.9			27.5			0.2		(0.1		)	27.6
Miscellaneous income	2.8			—			2.8			3.2		—			6.0
Interest expense	7.9			2.1			10.0			0.7		—			10.7
Provision (benefit) for income taxes	23.8			(2.0		)	21.8			1.0		—			22.8
Preferred stock dividend requirements	(0.6		)	(0.1		)	(0.7		)	—		—			(0.7		)
Net income (loss) attributed to common shareholder	38.3			(3.0		)	35.3			1.7		—			37.0
	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
	Regulated Utilities
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Nine Months Ended September 30, 2013
External revenues	$	946.0		$	227.1		$	1,173.1		$	—	$	—		$	1,173.1
Intersegment revenues	—			8.3			8.3			1.1		(9.4		)	—
Depreciation and amortization expense	66.9			11.8			78.7			0.5		(0.4		)	78.8
Miscellaneous income	6.5			0.1			6.6			10.3		—			16.9
Interest expense	23.8			6.4			30.2			1.7		—			31.9
Provision for income taxes	52.9			8.9			61.8			2.9		—			64.7
Preferred stock dividend requirements	(1.9		)	(0.4		)	(2.3		)	—		—			(2.3		)
Net income attributed to common shareholder	87.1			14.4			101.5			6.0		—			107.5
	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

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NOTE 18 — NEW ACCOUNTING PRONOUNCEMENTS

Recently Issued Accounting Guidance Not Yet Effective

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

ASU 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists," was issued in July 2013. The guidance states that an unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. There are certain exceptions, however, under which the unrecognized tax benefit would be presented in the balance sheet as a liability. The guidance is effective for reporting periods beginning after December 15, 2013. Adoption of this guidance is not expected to have a significant impact on our financial statements.

NOTE 19 — 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 services to ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under this agreement at our fully allocated cost.

We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC under which either party may be a service provider. Services are billed to WRPC under these agreements at our fully allocated cost.

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

(Millions)	September 30, 2013		December 31, 2012
Notes payable *
Integrys Energy Group	$	6.6	$	7.2
Accounts Payable
ATC	10.1		9.2
Liability related to income tax allocation
Integrys Energy Group	6.9		7.4

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

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.

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The following table shows activity associated with related party transactions:

	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2013		2012		2013		2012
Electric transactions
Sales to UPPCO	$	6.4	$	6.1	$	17.7	$	17.1
Natural gas transactions
Sales to Integrys Energy Services	0.1		0.1		0.3		0.5
Purchases from Integrys Energy Services	0.2		0.1		0.6		0.5
Interest expense (1)
Integrys Energy Group	0.1		0.1		0.4		0.4
Transactions with equity-method investees
Charges from ATC for network transmission services	24.6		23.5		73.8		70.6
Charges to ATC for services and construction	1.9		1.8		6.0		6.9
Net proceeds from WRPC sales of energy to MISO	—		0.6		—		2.4
Purchases of energy from WRPC	1.0		1.2		3.0		3.7
Charges to WRPC for operations	0.2		0.2		0.7		0.6
Equity earnings from WPS Investments, LLC (2)	2.5		2.5		7.6		7.6

⁽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, 2013, we had an 11.44% 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, 2012.

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 September 30						Change in 2013  Over 2012		Nine Months Ended September 30				Change in 2013  Over 2012
(Millions)	2013			2012					2013		2012
Electric utility operations	$	38.3		$	43.9		(12.8	)%	$	87.1	$	86.5	0.7	%
Natural gas utility operations	(3.0		)	(2.7		)	11.1	%	14.4		14.6		(1.4	)%
Other operations	1.7			1.3			30.8	%	6.0		6.1		(1.6	)%
Net income attributed to common shareholder	$	37.0		$	42.5		(12.9	)%	$	107.5	$	107.2	0.3	%

Third Quarter 2013 Compared with Third Quarter 2012

The $5.5 million decrease in our earnings was driven by the $5.9 million quarter-over-quarter negative impact of the reversal in 2012 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.

Nine Months 2013 Compared with Nine Months 2012

The $0.3 million increase in our earnings was driven by a $7.7 million after-tax increase in electric margins due to the 2013 PSCW rate order. This increase was partially offset by the $5.9 million period-over-period negative impact of the reversal in 2012 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.

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Electric Utility Segment Operations

	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30						Change in 2013 Over 2012
(Millions, except degree days)	2013			2012					2013			2012
Revenues	$	331.7		$	343.1		(3.3	)%	$	946.0		$	922.6		2.5	%
Fuel and purchased power costs	129.3			156.3			(17.3	)%	395.2			412.1			(4.1	)%
Margins	202.4			186.8			8.4	%	550.8			510.5			7.9	%
Operating and maintenance expense	100.2			87.1			15.0	%	291.8			267.8			9.0	%
Depreciation and amortization expense	23.6			20.3			16.3	%	66.9			60.5			10.6	%
Taxes other than income taxes	10.8			10.4			3.8	%	32.9			32.0			2.8	%
Operating income	67.8			69.0			(1.7	)%	159.2			150.2			6.0	%
Miscellaneous income	2.8			0.8			250.0	%	6.5			1.4			364.3	%
Interest expense	7.9			8.0			(1.3	)%	23.8			24.4			(2.5	)%
Other expense	(5.1		)	(7.2		)	(29.2	)%	(17.3		)	(23.0		)	(24.8	)%
Income before taxes	$	62.7		$	61.8		1.5	%	$	141.9		$	127.2		11.6	%
Sales in kilowatt-hours
Residential	775.0			832.2			(6.9	)%	2,157.5			2,165.8			(0.4	)%
Commercial and industrial	2,094.6			2,116.7			(1.0	)%	5,977.8			6,077.0			(1.6	)%
Wholesale	1,218.3			1,587.5			(23.3	)%	3,610.1			3,837.2			(5.9	)%
Other	7.0			7.2			(2.8	)%	22.9			23.2			(1.3	)%
Total sales in kilowatt-hours	4,094.9			4,543.6			(9.9	)%	11,768.3			12,103.2			(2.8	)%
Weather
Heating degree days	216			252			(14.3	)%	5,126			3,864			32.7	%
Cooling degree days	396			514			(23.0	)%	527			789			(33.2	)%

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

Third Quarter 2013 Compared with Third Quarter 2012

Margins

Electric utility segment margins increased$15.6 million, driven by:

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

• An approximate $4 million increase in margins due to a retail electric rate increase, effective January 1, 2013. For more information on our 2013 PSCW rate order, see Note 16, "Regulatory Environment."

• Partially offsetting these increases was an approximate $1 million net decrease in margins from residential and commercial and industrial customers due to variances related to sales volumes, including the impact of decoupling. The quarter-over-quarter impact of decoupling does not directly correlate with the quarter-over-quarter impact of the change in sales volumes, as our decoupling mechanism was changed in 2013. See Note 16, "Regulatory Environment," for more information.

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Operating Income

Operating income at the electric utility segment decreased $1.2 million. The decrease was driven by a $16.8 millionincrease in operating expenses, partially offset by the $15.6 millionincrease in margins discussed above. The increase in operating expenses was driven by:

• A $7.7 million increase in maintenance expense due to a greater number of planned outages for certain of our generation plants in 2013, driven primarily by an outage at Weston 3. Also included in this amount is maintenance expense associated with the recently acquired Fox Energy Center.

• A $3.3 million increase in depreciation and amortization expense mainly due to the acquisition of the Fox Energy Center, partially offset by a reduction in the depreciable basis of our Crane Creek Wind Project. The reduction was the result of our election to claim a Section 1603 Grant for the project in lieu of production tax credits.

• A $2.5 million increase in electric transmission expense.

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

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

Other Expense

Other expense decreased$2.1 million, driven by an increase in AFUDC due to environmental compliance projects at the Columbia plant.

Nine Months 2013 Compared with Nine Months 2012

Margins

Electric utility segment margins increased$40.3 million, driven by:

• An approximate $21 million increase in margins from fuel and purchased power costs that are not included in our fuel and purchased power cost recovery mechanism. The increase was primarily due to a decline in purchased power costs as a result of the acquisition of Fox Energy Company LLC, which had no impact on net income. The net difference between the purchased power costs and the costs of owning the plant are deferred for recovery or refund in a future rate case (the net difference is reflected in operating expenses below). 

• An approximate $13 million increase in margins due to a retail electric rate increase, effective January 1, 2013. For more information on our 2013 PSCW rate order, see Note 16, "Regulatory Environment."

• An approximate $7 million net increase in margins from residential and commercial and industrial customers due to variances related to sales volumes, including the impact of decoupling. The period-over-period impact of decoupling does not directly correlate with the period-over-period impact of the change in sales volumes as our decoupling mechanism was changed in 2013. See Note 16, "Regulatory Environment," for more information.

Operating Income

Operating income at the electric utility segment increased$9.0 million. The increase was driven by the $40.3 millionincrease in margins discussed above, partially offset by a $31.3 millionincrease in operating expenses. The increase in operating expenses was driven by:

• An $8.8 million increase in maintenance expense due to a greater number of planned outages for certain of our generation plants in 2013, driven primarily by an outage at Weston 3. Also included in this amount is maintenance expense associated with the recently acquired Fox Energy Center.

• A $6.9 million increase in electric transmission expense.

• A $6.4 million increase in depreciation and amortization expense mainly due to the acquisition of the Fox Energy Center, partially offset by a reduction in the depreciable basis of our Crane Creek Wind Project. The reduction is the result of our election to claim a Section 1603 Grant for the project in lieu of production tax credits.

• A $4.3 million increase due to our deferral of the net difference between actual and rate case-approved costs resulting from the purchase of Fox Energy Company LLC. Our 2013 PSCW rate order did not reflect this purchase or the related termination of the power purchase agreement.

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However, we did receive approval from the PSCW to defer ownership costs above or below our power purchase agreement expenses for recovery or refund in a future rate case.

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

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

In addition, a $3.4 million increase in employee benefit related expenses was more than offset by the $5.4 million positive impact of the deferral of certain components of pension and other employee benefit costs that will be recovered in a future rate proceeding as a result of our 2013 PSCW rate order. The increase in employee benefit related expenses was driven by the amortization of negative investment returns from prior years, which increased both the pension and other postretirement benefit expenses.

Other Expense

Other expense decreased$5.7 million, driven by an increase in AFUDC due to environmental compliance projects at the Columbia plant.

Natural Gas Utility Segment Operations

	Three Months Ended September 30						Change in 2013 Over 2012		Nine Months Ended September 30						Change in 2013 Over 2012
(Millions, except heating degree days)	2013			2012					2013			2012
Revenues	$	44.3		$	39.4		12.4	%	$	235.4		$	204.7		15.0	%
Natural gas purchased for resale	26.3			23.3			12.9	%	142.0			113.5			25.1	%
Margins	18.0			16.1			11.8	%	93.4			91.2			2.4	%
Operating and maintenance expense	15.8			15.6			1.3	%	48.0			48.2			(0.4	)%
Depreciation and amortization expense	3.9			3.8			2.6	%	11.8			11.4			3.5	%
Taxes other than income taxes	1.1			1.2			(8.3	)%	3.6			3.9			(7.7	)%
Operating income (loss)	(2.8		)	(4.5		)	(37.8	)%	30.0			27.7			8.3	%
Miscellaneous income	—			0.1			(100.0	)%	0.1			0.1			—	%
Interest expense	2.1			2.0			5.0	%	6.4			5.9			8.5	%
Other expense	(2.1		)	(1.9		)	10.5	%	(6.3		)	(5.8		)	8.6	%
Income (loss) before taxes	$	(4.9	)	$	(6.4	)	(23.4	)%	$	23.7		$	21.9		8.2	%
Retail throughput in therms
Residential	14.1			14.4			(2.1	)%	173.4			133.6			29.8	%
Commercial and industrial	15.8			11.8			33.9	%	107.4			80.0			34.3	%
Other	11.8			20.5			(42.4	)%	23.0			38.1			(39.6	)%
Total retail throughput in therms	41.7			46.7			(10.7	)%	303.8			251.7			20.7	%
Transport throughput in therms
Commercial and industrial	68.3			67.8			0.7	%	260.8			243.2			7.2	%
Total throughput in therms	110.0			114.5			(3.9	)%	564.6			494.9			14.1	%
Weather
Heating degree days	216			252			(14.3	)%	5,126			3,864			32.7	%

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 prudently incurred natural gas commodity costs are passed through to our customers in current rates. There was an approximate 27% and 4% increase in the average per-unit cost of natural gas sold during the three and nine month periods ended September 30, 2013, respectively, which had no impact on margins.

Third Quarter 2013 Compared with Third Quarter 2012

Margins

Natural gas utility segment margins increased $1.9 million. The increase in margins was driven by the quarter-over-quarter positive impact from the straight-line amortization of prior year decoupling deferrals, partially offset by a decrease in rates, both of which were approved in our rate order,

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effective January 1, 2013. See Note 16, "Regulatory Environment," for more information. The impact of the decrease in rates is not recognized evenly throughout the year, as recognition is based on volumes sold, which are generally lower in the third quarter.

Operating Loss

The operating loss at the natural gas utility segment decreased $1.7 million, primarily driven by the increase in margins discussed above. We also deferred $0.5 million of certain increases in our pension and other employee benefit costs that will be recovered in a future rate proceeding as a result of our 2013 rate order. There were no other individually significant items that impacted operating expenses.

Nine Months 2013 Compared with Nine Months 2012

Margins

Natural gas utility segment margins increased $2.2 million, driven by:

• An approximate $4 million net increase in margins, net of the impact of decoupling, driven by a 14.1% increase in volumes sold in 2013. In 2012, margins were lower due to unusually warm weather. In 2013, higher use per residential customer and an increase in residential customers also contributed to the increase in margins.

• A partially offsetting approximate $1 million decrease in margins related to our rate order effective January 1, 2013. See Note 16, "Regulatory Environment," for more information.

Operating Income

Operating income at the natural gas utility segment increased $2.3 million. This increase was primarily driven by the $2.2 million increase in margins discussed above and a $0.1 million decrease in operating expenses. Several individually insignificant items more than offset $1.6 million of higher amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites. In addition, we have deferred $1.6 million of certain increases in our pension and other employee benefit costs that will be recovered in a future rate proceeding as a result of our 2013 rate order.

Other Segment Operations

	Three Months Ended September 30					Change in 2013 Over 2012		Nine Months Ended September 30				Change in 2013 Over 2012
(Millions)	2013		2012					2013		2012
Operating income	$	0.2	$	(0.2	)	N/A		$	0.3	$	0.2	50.0	%
Other income	2.5		2.4			4.2	%	8.6		8.3		3.6	%
Income before taxes	$	2.7	$	2.2		22.7	%	$	8.9	$	8.5	4.7	%

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

Provision for Income Taxes

	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012
Effective Tax Rate	37.7	%	25.0	%	37.1	%	30.5	%

Third Quarter 2013 Compared with Third Quarter 2012

Our effective tax rate increased in the third quarter of 2013. In the fourth quarter of 2012, we elected to claim and subsequently received a Section 1603 Grant for our Crane Creek Wind Project in lieu of production tax credits (PTCs). As a result, we no longer claim wind PTCs on any of our qualifying facilities. In the third quarter of 2012, we also decreased our provision for income taxes by $5.9 million 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 Note 16, "Regulatory Environment," for more information.

Nine Months 2013 Compared with Nine Months 2012

Our effective tax rate increased in 2013. As discussed above, we no longer claim wind PTCs on any of our qualifying facilities, and we decreased our provision for income taxes by $5.9 million in 2012 as a result of our 2013 rate case settlement agreement.

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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, 2013, net cash provided by operating activities was $212.3 million, compared with $210.5 million for the same period in 2012. The $1.8 millionincrease in net cash provided by operating activities was driven by:

• A $71.4 million decrease in contributions to pension and other postretirement benefit plans.

• A $22.6 million period-over-period positive impact from the repayment of related party payables in 2012. Amounts previously paid to us for the unfunded nonqualified retirement plan were returned to related parties.

These increases were partially offset by:

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

• A $21.9 million increase in cash used to purchase natural gas that was injected into storage. The increase was driven by higher natural gas prices in 2013.

• A $11.8 million decrease in cash received from income taxes, primarily driven by refunds received in 2012 due to changes in estimated payments made for the prior year.

• An $8.4 million decrease in cash from customer prepayments and credit balances.

Investing Cash Flows

Net cash used for investing activities was $491.3 million during the nine months ended September 30, 2013, compared with $120.3 million for the same period in 2012. The $371.0 million increase in net cash used for investing activities was primarily due to $391.6 million of cash used in 2013 to purchase Fox Energy Company LLC. See Note 4, "Acquisition of Fox Energy Center," for additional information regarding this purchase. Also contributing to the increase was a $46.8 million increase in cash used for other capital expenditures (discussed below). These increases in net cash used were partially offset by the $69.0 million positive impact of the receipt of a Section 1603 Grant for the Crane Creek Wind Project in 2013.

Capital Expenditures

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

Reportable Segment (millions)	2013		2012		Change
Electric utility	$	537.8	$	104.0	$	433.8
Natural gas utility	26.6		22.0		4.6
WPS consolidated	$	564.4	$	126.0	$	438.4

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

Financing Cash Flows

Net cash provided by financing activities was $278.9 million during the nine months ended September 30, 2013, compared with $90.8 million of net cash used for financing activities for the same period in 2012. The $369.7 million period-over-period positive impact from financing activities was driven by:

• The borrowing of $200.0 million under our term credit facility in 2013 to partially finance the acquisition of Fox Energy Company LLC.

• A $160.0 million increase in equity contributions from Integrys Energy Group to support the acquisition of Fox Energy Company LLC.

• An $18.4 million increase in net borrowings of commercial paper.

• A $15.0 million decrease in payments made to Integrys Energy Group for return of capital.

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These increases were partially offset by a $22.0 million repayment of long-term debt in 2013.

Significant Financing Activities

For information on short-term debt, see Note 6, "Short-Term Debt and Lines of Credit."

For information on long-term debt, see Note 7, "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 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.

Future Capital Requirements and Resources

Contractual Obligations

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

			Payments Due By Period
(Millions)	Total Amounts Committed		2013		2014 to 2015		2016 to 2017		2018 and Later Years
Long-term debt principal and interest payments (1)	$	1,425.3	$	135.0	$	196.4	$	179.9	$	914.0
Operating lease obligations	16.6		0.3		1.5		1.1		13.7
Energy and transportation purchase obligations (2)	1,176.2		65.6		259.5		148.6		702.5
Purchase orders (3)	365.0		197.0		154.0		14.0		—
Pension and other postretirement funding obligations (4)	101.0		16.4		84.2		0.4		—
Uncertain tax positions	0.5		0.5		—		—		—
Total contractual cash obligations	$	3,084.6	$	414.8	$	695.6	$	344.0	$	1,630.2

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

⁽²⁾  The costs of energy and transportation 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 estimated future payments related to the manufactured gas plant remediation liability of $64.9 million at September 30, 2013, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 9, "Commitments and Contingencies," for more information about environmental liabilities. The table also does not reflect estimated future payments for the September 30, 2013 liability of $0.1 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 8, "Income Taxes," for more information about unrecognized tax benefits.

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Capital Requirements

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

(Millions)
Electric Utility
Environmental projects*	$	426
Acquisition of Fox Energy Center	392
Distribution and energy supply operations projects	335
Other projects	22
Natural Gas Utility
Distribution projects	92
Other projects	5
Total capital expenditures	$	1,272

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

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 2013 through 2015 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 currently have two shelf registration statements. Under these registration statements, we may issue up to $500.0 million of additional senior debt securities and up to $30.0 million of preferred stock. Amounts, prices, and terms will be determined at the time of future offerings.

At September 30, 2013, we 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 6, "Short-Term Debt and Lines of Credit," for more information on credit facilities and other short-term credit agreements. See Note 7, "Long-Term Debt," for more information on long-term debt.

Other Future Considerations

Climate Change

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

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

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

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

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

Tax Law Changes

In January 2013, President Obama signed into law the American Taxpayer Relief Act of 2012. This act extends 50% bonus tax depreciation through 2013 for most capital expenditures. This bonus tax depreciation extension is anticipated to generate future cash flows in excess of $15 million through 2015.

In June 2013, Governor Walker signed into law a three-year budget bill, 2013 Wisconsin Act 20, which is effective January 1, 2014. Among other provisions, this Act will conform the Wisconsin tax code to the federal tax code with respect to tax depreciation and basis differences. This tax law change will accelerate the generation of future cash flows in excess of $5 million over a five-year amortization period through 2018.

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

CRITICAL ACCOUNTING POLICIES

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

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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 2012 Annual Report on Form 10-K.

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Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of 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, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

For information on material legal proceedings and matters related to us and our subsidiary, see Note 9, "Commitments and Contingencies."

Item 1A.  Risk Factors

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

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

Dividend Restrictions

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 12, "Common Equity."

Item 5. Other Information

In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities." The new guidance requires enhanced disclosures about offsetting and related arrangements. ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities," was issued in January 2013. This guidance clarifies that the scope of ASU 2011-11 applies to certain derivatives included in the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. We adopted the new guidance on January 1, 2013. The following presents the retrospective application of this guidance for the year ended December 31, 2011:

	December 31, 2011
(Millions)	Gross Amount		Gross Amount Not Offset on the Balance Sheet, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	1.5	$	0.3	$	1.2
Total risk management assets	$	1.5			$	1.2
Derivative liabilities subject to master netting or similar arrangements	$	2.6	$	2.6	$	—
Derivative liabilities not subject to master netting or similar arrangements	6.9		—		6.9
Total risk management liabilities	$	9.5			$	6.9

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
	(Registrant)
Date:  November 7, 2013	/s/ Linda M. Kallas
	Linda M. Kallas
	Vice President and Controller
	(Duly Authorized Officer and Chief Accounting Officer)

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WISCONSIN PUBLIC SERVICE CORPORATION

EXHIBIT INDEX TO FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2013

Exhibit No.	Description
3.1	Amendment to the Wisconsin Public Service Corporation By-laws effective October 8, 2013
3.2	Wisconsin Public Service Corporation By-laws as in effect at October 8, 2013
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, 2013, 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

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