WISCONSIN PUBLIC SERVICE CORP - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - WISCONSIN PUBLIC SERVICE CORP	Financial_Report.xls
EX-31.2 - EXHIBIT - WISCONSIN PUBLIC SERVICE CORP	a2014q3wps10-qexhibit312.htm
EX-31.1 - EXHIBIT - WISCONSIN PUBLIC SERVICE CORP	a2014q3wps10-qexhibit311.htm
EX-32 - EXHIBIT - WISCONSIN PUBLIC SERVICE CORP	a2014q3wps10-qexhibit32.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2014

[ ] 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, 2014

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WISCONSIN PUBLIC SERVICE CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2014

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	Basis of Presentation	6
	Note 2	Proposed Merger of Parent Company with Wisconsin Energy Corporation	6
	Note 3	Acquisition of Fox Energy Center	6
	Note 4	Cash and Cash Equivalents	7
	Note 5	Risk Management Activities	7
	Note 6	Goodwill and Other Intangible Assets	8
	Note 7	Short-Term Debt and Lines of Credit	9
	Note 8	Income Taxes	9
	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	Fair Value	16
	Note 14	Miscellaneous Income	18
	Note 15	Regulatory Environment	19
	Note 16	Segments of Business	20
	Note 17	Related Party Transactions	21
	Note 18	New Accounting Pronouncements	22
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations			24
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			35
ITEM 4.	Controls and Procedures			36
PART II.	OTHER INFORMATION			37
ITEM 1.	Legal Proceedings			37
ITEM 1A.	Risk Factors			37
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			37
ITEM 6.	Exhibits			37
Signature				38
EXHIBIT INDEX				39

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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
FERC	Federal Energy Regulatory Commission
GAAP	United States Generally Accepted Accounting Principles
IBS	Integrys Business Support, LLC
IES	Integrys Energy Services, Inc.
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

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Forward-Looking Statements

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

Forward-looking statements involve a number of risks and uncertainties. Some risks and uncertainties 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, 2013, 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, 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;


•	The risk of disruption from the proposed merger of our parent, Integrys Energy Group, with Wisconsin Energy Corporation making it more difficult to maintain our business and operational relationships;


•	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;


•	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;


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


•	The ability to retain market-based rate authority;


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


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


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


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


•	The timely completion of capital projects within estimates, as well as the recovery of those costs through established mechanisms;


•	Potential business strategies, including acquisitions, which cannot be assured to be completed timely or within budgets;


•	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;


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


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


•	The impact of unplanned facility outages;


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


•	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 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.

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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)	2014			2013			2014			2013
Operating revenues	$	370.4		$	371.9		$	1,284.9		$	1,173.1

Cost of fuel, natural gas, and purchased power	138.8			151.3			595.4			528.2
Operating and maintenance expense	113.9			115.9			366.6			340.1
Depreciation and amortization expense	28.7			27.6			84.6			78.8
Taxes other than income taxes	11.1			11.9			36.3			36.5
Operating income	77.9			65.2			202.0			189.5

Miscellaneous income	5.6			6.0			19.5			16.9
Interest expense	14.6			10.7			42.9			31.9
Other expense	(9.0		)	(4.7		)	(23.4		)	(15.0		)

Income before taxes	68.9			60.5			178.6			174.5
Provision for income taxes	26.0			22.8			66.7			64.7
Net income	42.9			37.7			111.9			109.8

Preferred stock dividend requirements	(0.7		)	(0.7		)	(2.3		)	(2.3		)
Net income attributed to common shareholder	$	42.2		$	37.0		$	109.6		$	107.5

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

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WISCONSIN PUBLIC SERVICE CORPORATION



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	September 30		December 31
(Millions, except share and per share data)	2014		2013
Assets
Cash and cash equivalents	$	3.6	$	5.7
Accounts receivable and accrued unbilled revenues, net of reserves of $3.8 and $2.5, respectively	164.4		209.8
Receivables from related parties	1.6		5.2
Inventories
Fuel and gas	82.9		60.0
Materials and supplies, at average cost	38.2		34.9
Regulatory assets	30.0		46.2
Prepaid taxes	28.7		63.6
Other current assets	14.0		16.7
Current assets	363.4		442.1

Property, plant, and equipment, net of accumulated depreciation of $1,547.4 and $1,483.1, respectively	3,053.8		2,887.7
Regulatory assets	343.9		342.5
Goodwill	36.4		36.4
Pension and other postretirement benefit assets	224.0		145.1
Other long-term assets	108.2		107.5
Total assets	$	4,129.7	$	3,961.3

Liabilities and Shareholders’ Equity
Short-term debt	$	63.0	$	25.6
Current portion of long-term debt to parent	2.1		—
Accounts payable	143.1		131.8
Payables to related parties	11.4		13.8
Regulatory liabilities	8.8		38.0
Accrued interest	21.5		6.0
Other current liabilities	66.5		66.0
Current liabilities	316.4		281.2

Long-term debt to parent	3.6		6.3
Long-term debt	1,174.5		1,174.5
Deferred income taxes	672.5		619.5
Deferred investment tax credits	7.8		8.1
Regulatory liabilities	337.5		286.3
Environmental remediation liabilities	76.0		64.4
Pension and other postretirement benefit obligations	33.8		76.4
Payables to related parties	5.6		6.1
Other long-term liabilities	67.5		71.9
Long-term liabilities	2,378.8		2,313.5

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	765.9		723.5
Retained earnings	521.8		496.3
Total liabilities and shareholders’ equity	$	4,129.7	$	3,961.3

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

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WISCONSIN PUBLIC SERVICE CORPORATION



CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION (Unaudited)				September 30			December 31
(Millions, except share and per share data)				2014			2013
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				765.9			723.5
Retained earnings				521.8			496.3
Total common stock equity				1,383.3			1,315.4

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	2.1			2.4
	7.35	%	2016	3.6			3.9
Total				5.7			6.3
Current portion of long-term debt to parent				(2.1		)	—
Total long-term debt to parent				3.6			6.3

Long-term debt
First Mortgage Bonds
	Series		Year Due
	7.125	%	2023	0.1			0.1
Senior Notes
	Series		Year Due
	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
	4.752	%	2044	450.0			450.0
Total First Mortgage Bonds and Senior Notes				1,175.1			1,175.1
Unamortized discount on long-term debt				(0.6		)	(0.6		)
Total long-term debt				1,174.5			1,174.5
Total capitalization				$	2,612.6		$	2,547.4

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

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WISCONSIN PUBLIC SERVICE CORPORATION



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(Millions)	2014			2013
Operating Activities
Net income	$	111.9		$	109.8
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	84.6			78.8
Recoveries and refunds of regulatory assets and liabilities	2.6			(9.9		)
Bad debt expense	5.2			3.4
Pension and other postretirement (credit) expense	(4.4		)	16.9
Pension and other postretirement contributions	(46.7		)	(38.1		)
Deferred income taxes and investment tax credits	52.1			60.3
Termination of tolling agreement with Fox Energy Company LLC	—			(50.0		)
Deferrals to regulatory assets and liabilities	(17.8		)	6.8
Other	(10.5		)	(5.7		)
Changes in working capital
Accounts receivable and accrued unbilled revenues	43.6			25.5
Inventories	(26.5		)	0.9
Prepaid taxes	34.9			15.6
Other current assets	1.3			2.8
Accounts payable	(10.3		)	(27.5		)
Other current liabilities	8.0			22.7
Net cash provided by operating activities	228.0			212.3

Investing Activities
Capital expenditures	(222.9		)	(172.8		)
Acquisition of Fox Energy Company LLC	—			(391.6		)
Grant received related to Crane Creek wind project	—			69.0
Other	4.3			4.1
Net cash used for investing activities	(218.6		)	(491.3		)

Financing Activities
Short-term debt, net	37.4			19.0
Borrowing on term credit facility	—			200.0
Repayment of long-term debt	—			(22.0		)
Repayment of long-term debt to parent	(0.6		)	(0.6		)
Payment of dividends to parent	(83.9		)	(81.5		)
Equity contribution from parent	40.0			200.0
Return of capital to parent	—			(35.0		)
Preferred stock dividend requirements	(2.3		)	(2.3		)
Other	(2.1		)	1.3
Net cash (used for) provided by financing activities	(11.5		)	278.9

Net change in cash and cash equivalents	(2.1		)	(0.1		)
Cash and cash equivalents at beginning of period	5.7			6.5
Cash and cash equivalents at end of period	$	3.6		$	6.4

Cash paid for interest	$	27.9		$	22.7
Cash received for income taxes	$	(5.1	)	$	(2.4	)

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

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WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY

CONDENSED NOTES TO FINANCIAL STATEMENTS (Unaudited)

September 30, 2014

Note 1—Basis of Presentation

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, 2013. 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—Proposed Merger of Parent Company with Wisconsin Energy Corporation

In June 2014, our parent company, Integrys Energy Group, entered into an Agreement and Plan of Merger with Wisconsin Energy Corporation. This transaction was approved unanimously by the Boards of Directors of both companies. It is subject to various approvals, including the FERC, Federal Communications Commission, PSCW, and other regulatory commissions. In addition, this transaction is subject to the approval of the shareholders of both companies, for which special shareholder meetings will be held on November 21, 2014. On October 24, 2014, the Department of Justice closed its review of the transaction and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. The transaction is also subject to other customary closing conditions. The transaction is expected to close in the summer of 2015.

Note 3—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 being 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 6, 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. The amount is being amortized over a nine-year period that began on January 1, 2014.

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We received regulatory approval to defer incremental costs incurred in 2013 associated with the purchase of the facility. These costs are included in our 2015 proposed retail electric rate increase. See Note 15, Regulatory Environment, for more information. Our rate order effective January 1, 2014, included the costs of operating the Fox Energy Center.

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 4—Cash and Cash Equivalents

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

Construction costs funded through accounts payable totaled $56.2 million at September 30, 2014, and $29.5 million at September 30, 2013. These costs were treated as noncash investing activities.

Note 5—Risk Management Activities

We use physical and financial derivative contracts to manage commodity costs. None of these derivatives are designated as hedges for accounting purposes. The electric and natural gas utility segments use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs. The electric utility segment also uses financial derivative contracts to reduce price risk related to coal transportation costs and financial transmission rights (FTRs) to manage electric transmission congestion costs.

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



		September 30, 2014
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	1.4	$	0.4
FTRs	Other Current	3.4		0.4
Petroleum product contracts	Other Current	—		0.3
Coal contracts	Other Current	—		2.3
Coal contracts	Other Long-term	2.4		0.1
	Other Current	4.8		3.4
	Other Long-term	2.4		0.1
Total		$	7.2	$	3.5


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



		December 31, 2013
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	0.6	$	0.1
FTRs	Other Current	1.5		0.3
Petroleum product contracts	Other Current	0.1		—
Coal contracts	Other Current	—		1.9
Coal contracts	Other Long-term	0.2		0.8
	Other Current	2.2		2.3
	Other Long-term	0.2		0.8
Total		$	2.4	$	3.1


*	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, 2014
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	4.8	$	1.1	$	3.7
Derivative assets not subject to master netting or similar arrangements	2.4				2.4
Total risk management assets	$	7.2			$	6.1

Derivative liabilities subject to master netting or similar arrangements	$	1.1	$	1.1	$	—
Derivative liabilities not subject to master netting or similar arrangements	2.4				2.4
Total risk management liabilities	$	3.5			$	2.4

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	December 31, 2013
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	2.2	$	0.6	$	1.6
Derivative assets not subject to master netting or similar arrangements	0.2				0.2
Total risk management assets	$	2.4			$	1.8

Derivative liabilities subject to master netting or similar arrangements	$	0.4	$	0.4	$	—
Derivative liabilities not subject to master netting or similar arrangements	2.7				2.7
Total risk management liabilities	$	3.1			$	2.7

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

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, 2014		December 31, 2013
Cash collateral provided to others related to contracts under master netting or similar arrangements *	$	4.3	$	3.1
Cash collateral received from others related to contracts under master netting or similar arrangements *	—		0.2


*	Cash collateral provided to others is reflected in other current assets and cash collateral received from others is reflected in other current liabilities on the balance sheets.

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	2014			2013			2014			2013
Natural gas	Balance Sheet — Regulatory assets (current)	$	(0.3	)	$	(0.2	)	$	(0.4	)	$	0.3
Natural gas	Balance Sheet — Regulatory liabilities (current)	0.5			—			0.4			(0.1		)
FTRs	Balance Sheet — Regulatory assets (current)	0.7			0.8			(0.2		)	—
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.3		)	—			0.7			(0.3		)
Petroleum	Balance Sheet — Regulatory assets (current)	(0.4		)	0.1			(0.4		)	—
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)	(0.9		)	(0.6		)	(1.0		)	2.1
Coal	Balance Sheet — Regulatory assets (long-term)	0.1			0.2			0.7			4.2
Coal	Balance Sheet — Regulatory liabilities (current)	—			—			—			(0.3		)
Coal	Balance Sheet — Regulatory liabilities (long-term)	(0.2		)	1.5			2.3			(0.7		)

We had the following notional volumes of outstanding derivative contracts:

(Millions)

September 30, 2014

December 31, 2013

Commodity

Purchases

Sales

Other Transactions

Purchases

Sales

Other Transactions

Natural gas (therms)

1,479.9

—

N/A

2,242.5

7.0

N/A

FTRs (kilowatt-hours)

N/A

5,644.0

N/A

3,427.0

Petroleum products (barrels)

0.1

—

N/A

0.1

—

N/A

Coal contract (tons)

3.4

—

N/A

4.8

—

N/A

Note 6—Goodwill and Other Intangible Assets

We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2014, and 2013. In the second quarter of 2014, we completed our annual goodwill impairment test, and no impairment resulted from this test.

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Our intangible assets listed below 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 were included in other long-term assets on the balance sheets.



	September 30, 2014							December 31, 2013
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Contractual service agreements	$	15.6	$	(3.5	)	$	12.1	$	15.6	$	(1.8	)	$	13.8

In October 2014, we received approval from the PSCW to upgrade the combustion turbine generators at the Fox Energy Center earlier than planned. As a result of this approval, we shortened the amortization period of one of our service agreements. The remaining weighted-average amortization period for these intangible assets at September 30, 2014, was approximately four years. Since we have approval from the PSCW to recover the value of our service agreements from customers over seven years, the increase in amortization due to the shorter amortization period will be recorded to a regulatory asset. This regulatory asset will be amortized to reflect the seven-year recovery period.

The table below shows our amortization expense recognized in the statements of income:



	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2014		2013		2014		2013
Amortization recorded in depreciation and amortization expense	$	0.5	$	0.6	$	1.7	$	1.2

The following table shows our estimated amortization expense for the next five years, including amounts recorded through September 30, 2014:



	For the Year Ending December 31
(Millions)	2014		2015		2016		2017		2018
Amortization to be recorded in depreciation and amortization expense	$	2.2	$	2.2	$	2.2	$	1.7	$	1.2
Amortization to be recorded in regulatory assets	0.3		1.0		1.0		0.5		—

Note 7—Short-Term Debt and Lines of Credit

Our outstanding short-term borrowings were as follows:



(Millions, except percentages)	September 30, 2014			December 31, 2013
Commercial paper	$	63.0		$	25.6
Average interest rate on commercial paper	0.18		%	0.14		%

The commercial paper outstanding at September 30, 2014, had maturity dates ranging from October 1, 2014, through October 7, 2014.

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2014, and 2013, was $25.7 million and $88.4 million, respectively.

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



(Millions)	Maturity	September 30, 2014		December 31, 2013
Revolving credit facility ⁽¹⁾	05/17/2014	$	—	$	135.0
Revolving credit facility ⁽²⁾	05/07/2015	135.0		—
Revolving credit facility	06/13/2017	115.0		115.0
Total short-term credit capacity		$	250.0	$	250.0

Less:
Commercial paper outstanding		63.0		25.6
Available capacity under existing agreements		$	187.0	$	224.4


⁽¹⁾	This credit facility was terminated and replaced with a new credit facility in May 2014.


⁽²⁾	We requested approval from the PSCW to extend this facility through May 8, 2019.

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.

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The table below shows our effective tax rates:



	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Effective tax rate	37.7	%	37.7	%	37.3	%	37.1	%

Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for state income tax obligations. No other items had a significant impact on our effective tax rates during the three and nine months ended September 30, 2014, and 2013.

During the three and nine months ended September 30, 2014, 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, 2014.



				Payments Due By Period
(Millions)	Year Contracts Extend Through	Total Amounts Committed		2014		2015		2016		2017		2018		Later Years
Electric utility
Purchased power	2029	$	944.0	$	19.1	$	118.9	$	42.3	$	52.8	$	55.8	$	655.1
Coal supply and transportation	2018	124.9		15.6		45.1		21.1		22.2		20.9		—
Natural gas utility supply and transportation	2024	255.6		12.1		45.4		43.4		43.0		42.5		69.2
Total		$	1,324.5	$	46.8	$	209.4	$	106.8	$	118.0	$	119.2	$	724.3

We also had commitments of $384.8 million in the form of purchase orders issued to various vendors at September 30, 2014, 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, and


•	a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. We announced that certain Weston and Pulliam units mentioned in the Consent Decree will be retired early, in June 2015. In July 2014, we filed for approval from the PSCW to reclassify the undepreciated book value of the retired units to a regulatory asset in 2015, with recovery of a full return, and for future amortization at current depreciable rates. We believe that we will receive approval of this treatment from the PSCW.

We received approval from the PSCW in our 2014 rate order to recover prudently incurred 2014 costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that prudently incurred costs after 2014 will be recoverable from customers based on past precedent with the PSCW.

The majority of the beneficial environmental projects that we proposed have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.

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

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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, 2014. 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 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, 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, 2014, no decision had been made on how to address this requirement. Therefore, retirement of the Columbia and Edgewater units mentioned in the Consent Decree was not considered probable.

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

All of the beneficial environmental projects that we proposed have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.

Weston Title V Air Permit:

In August 2013, the WDNR issued the Weston Title V 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 Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also filed Petitions for Judicial Review and requests for contested case proceedings regarding various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In May 2014, the WDNR referred the contested case to the administrative law judge, and a schedule was set for dispositive motions, which have now been fully briefed. We filed an application to amend some permit terms that, if accepted, would resolve many of the outstanding issues. In September 2014, the WDNR issued a draft permit that resolves several issues we raised in the contested case. If these permit terms are finalized, we will withdraw nine claims under the Petition. The new permit does raise an additional issue regarding the sorbent injection rate, which we will challenge and is discussed below.

In May 2014, the WDNR issued an NOV alleging that we failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification. We and the WDNR have begun discussing resolution of this matter. In May 2014, the WDNR issued a Notice of Inquiry (NOI) alleging that we failed to comply with excess emission summary reporting requirements in the 2013 Weston Title V permit. We believe that the requirements identified in the NOV and NOI are stayed pursuant to state law pending the outcome of the Weston Title V air permit contested case and have filed a motion with the administrative law judge requesting confirmation of the stay. Briefing has been completed on this issue and we anticipate a decision from the administrative law judge in the fourth quarter of 2014.

We do not expect these matters 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 from fuel combusted by a minimum of 90%, or meet certain mercury emission limits annually based on gigawatt-hours of electricity produced. 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.

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 state mercury rule to be consistent with the MATS rule. Projects approved and initiated to address the State of Wisconsin mercury rule are expected to ensure compliance with the mercury limits in the MATS rule.

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We will be in compliance with the State of Wisconsin's mercury rule at the end of 2014. In addition, we are making progress toward compliance with the MATS rule in 2015. We estimated capital costs of approximately $9 million for our wholly owned plants to achieve the required reductions for MATS compliance, of which approximately $5 million has been expended as of September 30, 2014. The capital costs are expected to be recovered 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 (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. The case was appealed to the United States Supreme Court (Supreme Court), and in April 2014, the Supreme Court upheld the CSAPR rule and remanded the case to the Court of Appeals for the D.C. Circuit. In June 2014, the EPA requested that the Court of Appeals lift the stay of CSAPR. Further, the EPA asked the Court of Appeals to change the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets would apply in 2015 and 2016, and Phase 2 emissions budgets would apply to 2017 and beyond. In October 2014, the Court of Appeals granted the EPA's request and lifted the stay on CSAPR. There are remaining issues before the Court of Appeals, and there will need to be additional changes before CSAPR is implemented. As a result, it is premature to speculate on what additional controls or other actions, if any, we may be required to implement. We expect to recover any future compliance costs in future rates.

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). Although particulate emissions also contribute to visibility impairment, the WDNR's modeling for Pulliam Unit 8, the only unit covered by BART, has shown the impairment to be so insignificant that additional capital expenditures or controls may not be warranted.

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 "multisite" 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. Our balance sheets include liabilities of $76.0 million that we have estimated and accrued for as of September 30, 2014, for future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of September 30, 2014, cash expenditures for environmental remediation not yet recovered in rates were $11.9 million. Our balance sheets include a regulatory asset of $87.9 million at September 30, 2014, which is net of insurance recoveries, 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 are 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.

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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)	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	2.2		$	2.7		$	6.5		$	8.1		$	1.9		$	2.6		$	5.8		$	7.9
Interest cost	8.6			7.6			25.8			22.9			2.7			3.4			8.8			10.1
Expected return on plan assets	(16.0		)	(14.3		)	(48.0		)	(42.9		)	(4.0		)	(3.7		)	(12.0		)	(11.1		)
Loss on plan settlement	—			—			0.4			—			—			—			—			—
Amortization of prior service cost (credit)	0.1			0.9			0.4			2.7			(2.3		)	(0.6		)	(5.7		)	(1.6		)
Amortization of net actuarial losses	3.7			6.0			11.2			18.0			0.7			1.9			2.0			5.6
Net periodic benefit cost (credit)	$	(1.4	)	$	2.9		$	(3.7	)	$	8.8		$	(1.0	)	$	3.6		$	(1.1	)	$	10.9

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 or liabilities.

In March 2014, we remeasured the obligations of certain other postretirement benefit plans in which we are both a sponsor and participant. The remeasurement was necessary because we will replace the current retiree medical plans for participants age 65 and older with a Medicare Advantage plan starting in 2015.

Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. During the nine months ended September 30, 2014, we contributed $46.6 million to our pension plans and $0.1 million to our other postretirement benefit plans. We do not expect to contribute any additional amounts to our pension plans during the remainder of 2014. We expect to contribute an additional $3.0 million to our other postretirement benefit plans during the remainder of 2014, dependent upon various factors affecting us, including our liquidity position and possible 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 income 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)	2014		2013		2014		2013
Stock options	$	0.1	$	0.2	$	0.4	$	0.5
Performance stock rights	0.1		0.4		3.9		1.7
Restricted share units	0.7		0.8		2.7		2.6
Total stock-based compensation expense	$	0.9	$	1.4	$	7.0	$	4.8
Deferred income tax benefit	$	0.4	$	0.6	$	2.8	$	1.9

No stock-based compensation cost was capitalized during the three and nine months ended September 30, 2014, and 2013.

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's common stock. The expected stock price volatility is estimated using its 10-year historical volatility. The following table shows the assumptions incorporated into the valuation model:



		February 2014 Grant
Expected term		8 years
Risk-free interest rate		0.12% – 2.88%
Expected dividend yield		5.28%
Expected volatility		18%

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The weighted-average fair value per stock option granted during the nine months ended September 30, 2014, and 2013, was $6.70 and $6.03, respectively.

A summary of stock option activity for the nine months ended September 30, 2014, and information related to outstanding and exercisable stock options at September 30, 2014, 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, 2013	49,993		$	53.03
Granted	13,890		55.23
Exercised	(17,333	)	51.48
Outstanding at September 30, 2014	46,550		$	54.26	8.2	$	0.5
Exercisable at September 30, 2014	9,270		$	52.15	7.2	$	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, 2014. This is calculated as the difference between Integrys Energy Group’s closing stock price on September 30, 2014, 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, 2014, and 2013, was not significant.

Effective October 24, 2014, Integrys Energy Group's Board of Directors accelerated the vesting of all unvested stock options held by active employees in order to mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees. All stock options awarded to active employees also became exercisable as of this date. As a result of this modification, an insignificant amount of unrecognized compensation expense related to unvested and outstanding stock options at September 30, 2014, will be recognized in the fourth quarter of 2014.

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's common stock. The expected volatility is estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at September 30:



		2014
Risk-free interest rate		0.06% – 0.60%
Expected dividend yield		5.28% – 5.33%
Expected volatility		17% – 23%

A summary of the activity for the nine months ended September 30, 2014, 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, 2013	5,561		$	45.16
Granted	1,113		44.28
Award modifications ⁽¹⁾	2,295		85.09
Adjustment for shares not distributed	(3,347	)	41.90
Outstanding at September 30, 2014	5,622		$	63.23

⁽¹⁾

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


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

The weighted-average grant date fair value of performance stock rights awarded during the nine months ended September 30, 2014, and 2013, was $44.28 and $48.50 per performance stock right, respectively.

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A summary of the activity for the nine months ended September 30, 2014, related to performance stock rights accounted for as liability awards is presented below:



	Performance Stock Rights
Outstanding at December 31, 2013	9,222
Granted	4,440
Award modifications *	(2,295	)
Adjustment for shares not distributed	(379	)
Outstanding at September 30, 2014	10,988

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of September 30, 2014, was $77.97 per performance stock right.

No shares of Integrys Energy Group's common stock were distributed for performance stock rights during the nine months ended September 30, 2014, because the performance percentage was below the threshold payout level for those rights that were eligible for distribution. The total intrinsic value of shares distributed during the nine months ended September 30, 2013, was not significant.

Effective October 24, 2014, Integrys Energy Group's Board of Directors approved the acceleration of the distribution of certain performance stock rights held by active employees. For those performance stock rights with a performance period ending December 31, 2014, a portion of the estimated distribution will be made in December 2014. This change was made to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees.

As of September 30, 2014, $1.9 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.4 years.

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, 2014, is presented below:



	Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2013	67,741		$	52.06
Granted	28,725		55.23
Dividend equivalents	2,262		54.46
Vested and released	(28,325	)	49.50
Transfers	332		54.55
Forfeited	(804	)	54.64
Outstanding at September 30, 2014	69,931		$	54.46

The weighted-average grant date fair value of restricted share units awarded during the nine months ended September 30, 2014, and 2013, was $55.23 and $56.05 per unit, respectively.

The total intrinsic value of restricted share unit awards vested and released during the nine months ended September 30, 2014, and 2013, was

$1.5 million and $1.6 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, 2014, and 2013, was not significant.

As of September 30, 2014, $3.9 million of compensation cost related to unvested and outstanding restricted share units was expected to be recognized over a weighted-average period of 2.3 years.

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

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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 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, 2014, our total restricted retained earnings were $493.9 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $31.2 million at September 30, 2014.

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, 2014, we paid common stock dividends of $83.9 million to Integrys Energy Group and received $40.0 million of equity contributions from Integrys Energy Group.

Note 13—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.

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 only when 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 department is separate and distinct from the trading function. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.

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



	September 30, 2014
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.8	$	0.6	$	—	$	1.4
Financial transmission rights (FTRs)	—		—		3.4		3.4
Coal contracts	—		—		2.4		2.4
Total	$	0.8	$	0.6	$	5.8	$	7.2

Risk management liabilities
Natural gas contracts	$	0.4	$	—	$	—	$	0.4
FTRs	—		—		0.4		0.4
Petroleum product contracts	0.3		—		—		0.3
Coal contracts	—		—		2.4		2.4
Total	$	0.7	$	—	$	2.8	$	3.5



	December 31, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.6	$	—	$	—	$	0.6
FTRs	—		—		1.5		1.5
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		0.2		0.2
Total	$	0.7	$	—	$	1.7	$	2.4

Risk management liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
FTRs	—		—		0.3		0.3
Coal contracts	—		—		2.7		2.7
Total	$	0.1	$	—	$	3.0	$	3.1

The risk management assets and liabilities listed in the tables above include NYMEX futures and options, financial contracts used to manage transmission congestion costs in the MISO market, and physical commodity contracts. NYMEX contracts are valued using the NYMEX end-of-day settlement price, which is a Level 1 input. Over-the-counter natural gas contracts are valued based on quoted market prices received from counterparties and are classified as Level 2. The valuation of physical coal contracts is categorized in Level 3 as it is based on significant assumptions made to extrapolate prices from the last quoted period through the end of the transaction term. The valuation of FTRs is derived from historical data from MISO, which is also considered a Level 3 input. See Note 5, Risk Management Activities, for more information.

There were no transfers between the levels of the fair value hierarchy during the three or nine months ended September 30, 2014, and 2013.

The amounts listed in the table below represent the range of unobservable inputs used in the valuations that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3 at September 30, 2014:

Fair Value (Millions)

Assets

Liabilities

Valuation Technique

Unobservable Input

Average or Range

FTRs

3.4

0.4

Market-based

Forward market prices ($/megawatt-month) ⁽¹⁾

$187.89

Coal contracts

2.4

Market-based

Forward market prices ($/ton) ⁽²⁾

$12.31 – $15.50


⁽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, 2014									Nine Months Ended September 30, 2014
(Millions)	FTRs			Coal Contracts			Total			FTRs			Coal Contracts			Total
Balance at the beginning of period	$	4.0		$	0.9		$	4.9		$	1.2		$	(2.5	)	$	(1.3	)
Net realized gains included in earnings	0.2			—			0.2			1.0			—			1.0
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0.4			(1.0		)	(0.6		)	0.5			2.0			2.5
Purchases	—			—			—			4.3			—			4.3
Settlements	(1.6		)	0.1			(1.5		)	(4.0		)	0.5			(3.5		)
Balance at the end of period	$	3.0		$	—		$	3.0		$	3.0		$	—		$	3.0

	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

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, 2014				December 31, 2013
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	1,174.5	$	1,250.1	$	1,174.5	$	1,176.5
Long-term debt to parent	5.7		6.0		6.3		7.1
Preferred stock	51.2		57.1		51.2		61.4

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, and outstanding commercial paper, the carrying amount for each such item approximates fair value.

Note 14—Miscellaneous Income

Total miscellaneous income was as follows:



	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2014		2013		2014		2013
Equity portion of AFUDC	$	2.2	$	2.9	$	8.5	$	6.6
Earnings from equity method investments	2.9		2.8		8.5		8.6
Key executive life insurance for retired employees	0.1		0.1		1.5		1.0
Other	0.4		0.2		1.0		0.7
Total miscellaneous income	$	5.6	$	6.0	$	19.5	$	16.9

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Note 15—Regulatory Environment

Wisconsin

2015 Rate Case

In April 2014, we filed an application with the PSCW to increase retail electric rates $76.8 million and to decrease natural gas rates $1.6 million, with rates expected to be effective January 1, 2015. Our request reflects a 10.60% return on common equity and a target common equity ratio of 50.51% in our regulatory capital structure. In May 2014, we filed our proposed electric and natural gas rate designs with the PSCW. These rate designs include significantly higher fixed charges, which better matches the related fixed costs of providing service. The PSCW is reviewing the new rate design as part of the rate-setting process.

The proposed retail electric rate increase is primarily driven by the completion of a partial refund to customers of the 2013 fuel cost over-collections in 2014 rates, which kept rates flat in 2014, as well as a reduction in refunds associated with decoupling. In 2015, fuel and purchased power costs are expected to increase, as are transmission costs and general inflation. The proposed retail electric rate increase also includes our request to recover deferred costs over four years related to the 2013 acquisition of the Fox Energy Center. Finally, capital costs associated with both previously approved environmental upgrades at the Columbia plant as well as our efforts to improve electric reliability by converting historically low performance overhead distribution lines to underground are also contributing to the requested increase in retail electric rates. The requested increase in retail electric rates was partially offset by the refund of a portion of the remaining 2013 fuel cost over-collections to customers. However, in July 2014, the PSCW authorized us to refund the remaining 2013 fuel cost over-collections to customers, all in 2014 rates, which differed from the original application to refund them in 2015 and 2016 rates.

The proposed retail natural gas rate decrease is being driven by 2013 decoupling over-collections, which will be refunded to customers in 2015. An increase in non-fuel operating and maintenance costs, including the impact of general inflation, and an increase in return on equity partially offset the effect of the 2013 decoupling over-collections.

In August 2014, the PSCW staff submitted testimony and recommended a rate increase of $28.7 million for retail electric and a rate decrease of $13.6 million for retail natural gas, which reflected a 10.20% return on common equity. PSCW staff recommended a common equity ratio of 50.27% for our regulatory capital structure. The PSCW held both technical and public hearings in September 2014. In October 2014, we issued an initial brief revising our requested retail electric rate increase to approximately $48 million. The requested retail natural gas rate decrease was also revised to a decrease of approximately $8 million. The revised request is lower than the initial application and is primarily driven by certain PSCW staff adjustments, but does not include adjustments for the contested issues of incentive compensation and the customer billing system project. The revised request reflects a 10.20% return on common equity and a common equity ratio of 50.27% in our regulatory capital structure. A final decision by the PSCW on the 2015 rates is expected before December 31, 2014.

2014 Rates

In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.14% in our regulatory capital structure. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 9, Commitments and Contingencies, for more information. Additionally, the order required us to terminate our decoupling mechanism, beginning January 1, 2014.

2013 Rates

In December 2012, the PSCW issued a final written order, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% return on common equity and a common equity ratio of 51.61% in our regulatory capital structure. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that are being recovered in 2014 rates. 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 order also authorized the recovery of direct Cross State Air Pollution Rule costs incurred through the end of 2012. Lastly, the order authorized us to switch from production tax credits to Section 1603 Grants for the Crane Creek wind project.

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A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included 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.

Michigan

2015 Rate Case

In October 2014, we filed an application with the MPSC to increase retail electric rates $5.7 million, with interim rates expected to be effective in April 2015. Our request reflects a 10.60% return on common equity and a target common equity ratio of 50.48% in our regulatory capital structure. The proposed retail electric rate increase is primarily driven by the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generating plants. Expenses are expected to increase for line clearance, customer relations, uncollectible expenses, injuries and damages, and general inflation. The proposal includes annual rate increases to be implemented over a three-year period.

Note 16—Segments of Business

At September 30, 2014, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are our regulated electric utility operations and our regulated natural gas utility operations. Our 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 tables below present 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, 2014
External revenues	$	327.4		$	43.0		$	370.4		$	—	$	—		$	370.4
Intersegment revenues	—			3.4			3.4			0.3		(3.7		)	—
Depreciation and amortization expense	24.6			4.1			28.7			0.1		(0.1		)	28.7
Miscellaneous income	2.1			—			2.1			3.5		—			5.6
Interest expense	11.4			2.6			14.0			0.6		—			14.6
Provision (benefit) for income taxes	27.3			(2.3		)	25.0			1.0		—			26.0
Preferred stock dividend requirements	(0.7		)	—			(0.7		)	—		—			(0.7		)
Net income (loss) attributed to common shareholder	43.1			(3.0		)	40.1			2.1		—			42.2

	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
Nine Months Ended September 30, 2014
External revenues	$	940.2		$	344.7		$	1,284.9		$	—	$	—		$	1,284.9
Intersegment revenues	—			10.5			10.5			1.0		(11.5		)	—
Depreciation and amortization expense	72.3			12.2			84.5			0.5		(0.4		)	84.6
Miscellaneous income	8.4			0.1			8.5			11.0		—			19.5
Interest expense	33.5			7.8			41.3			1.6		—			42.9
Provision for income taxes	52.5			11.2			63.7			3.0		—			66.7
Preferred stock dividend requirements	(2.0		)	(0.3		)	(2.3		)	—		—			(2.3		)
Net income attributed to common shareholder	85.2			17.6			102.8			6.8		—			109.6

	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

Note 17—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.

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Effective January 1, 2014, after approval by the PSCW and other state commissions, a new affiliated interest agreement (Non-IBS AIA) went into effect and replaced certain prior agreements. It governs the provision and receipt of services by Integrys Energy Group subsidiaries, except that IBS will continue to provide services only under the existing IBS affiliated interest agreement (IBS AIA). Services under the Non-IBS AIA are subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary are priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary are priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary are priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to IBS are priced at cost.

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, 2014		December 31, 2013
Notes payable *
Integrys Energy Group	$	5.7	$	6.3
Accounts Payable
ATC	8.2		10.4
Liability related to income tax allocation
Integrys Energy Group	6.2		6.7


*	WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group. At September 30, 2014, the current portion of the note payable was $2.1 million.

The following table shows activity associated with related party transactions:



	Three Months Ended September 30				Nine Months Ended September 30
(Millions)	2014		2013		2014		2013
Electric transactions
Sales to UPPCO ⁽¹⁾	$	4.1	$	6.4	$	15.3	$	17.7
Sales to Integrys Transportation Fuels, LLC	0.1		—		0.1		—
Natural gas transactions
Sales to IES	0.3		0.1		0.5		0.3
Purchases from IES	0.1		0.2		2.5		0.6
Interest expense ⁽²⁾
Integrys Energy Group	0.2		0.1		0.4		0.4
Transactions with equity method investees
Charges from ATC for network transmission services	24.7		24.6		74.2		73.8
Charges to ATC for services and construction	2.4		1.9		7.5		6.0
Purchases of energy from WRPC	0.9		1.0		3.0		3.0
Charges to WRPC for operations	0.3		0.2		1.0		0.7
Equity earnings from WPS Investments, LLC ⁽³⁾	2.6		2.5		7.7		7.6


⁽¹⁾	Includes sales through the date of the sale of UPPCO in August 2014, by Integrys Energy Group.


⁽²⁾	WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.


⁽³⁾	WPS Investments, LLC is a consolidated subsidiary of Integrys Energy Group that is jointly owned by Integrys Energy Group and us. At September 30, 2014, we had an 11.05% 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.

Note 18—New Accounting Pronouncements

Recently Issued Accounting Guidance Not Yet Effective

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the revenue recognition requirements in Topic 605 of the FASB's Accounting Standards Codification and most industry-specific guidance throughout the Codification. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is effective for us for the reporting period ending March 31, 2017. The standard requires either

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retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

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

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2013.

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 2014 Over 2013		Nine Months Ended September 30				Change in 2014 Over 2013
(Millions)	2014			2013			Change in 2014 Over 2013		2014		2013		Change in 2014 Over 2013
Electric utility operations	$	43.1		$	38.3		12.5	%	$	85.2	$	87.1	(2.2	)%
Natural gas utility operations	(3.0		)	(3.0		)	—	%	17.6		14.4		22.2	%
Other operations	2.1			1.7			23.5	%	6.8		6.0		13.3	%
Net income attributed to common shareholder	$	42.2		$	37.0		14.1	%	$	109.6	$	107.5	2.0	%

Third Quarter 2014 Compared with Third Quarter 2013

The $5.2 million increase in our earnings was driven by an increase in electric utility margins related to our 2014 PSCW electric rate order effective January 1, 2014.

Nine Months 2014 Compared with Nine Months 2013

The $2.1 million increase in our earnings was driven by:


•	A $16.6 million net after-tax increase in margins related to our 2014 PSCW electric and natural gas rate orders effective January 1, 2014.


•	An $8.8 million after-tax increase in natural gas utility margins due to variances in sales volumes, net of decoupling. The increase was driven by colder than normal weather in 2014, as our decoupling mechanism was terminated effective January 1, 2014.


•	A $3.4 million increase in electric wholesale margins driven by higher prices, primarily due to the pass-through of increased generation costs to customers.

These increases were partially offset by:

•

A $19.3 million after-tax increase in electric and natural gas utility operating expenses, driven by an increase in maintenance expense. Higher depreciation and amortization expense, increased electric transmission expense, and increased costs associated with the acquisition and operation of the Fox Energy Center also contributed to the increase. We acquired the Fox Energy Center at the end of the first quarter of 2013. These increases were partially offset by lower benefit costs.


•	An $8.0 million after-tax increase in interest expense on long-term debt, driven by higher average outstanding long-term debt during 2014.

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Electric Utility Segment Operations



	Three Months Ended September 30						Change in 2014 Over 2013		Nine Months Ended September 30						Change in 2014 Over 2013
(Millions, except degree days)	2014			2013			Change in 2014 Over 2013		2014			2013			Change in 2014 Over 2013
Revenues	$	327.4		$	331.7		(1.3	)%	$	940.2		$	946.0		(0.6	)%
Fuel and purchased power costs	114.8			129.3			(11.2	)%	355.2			395.2			(10.1	)%
Margins	212.6			202.4			5.0	%	585.0			550.8			6.2	%

Operating and maintenance expense	97.6			100.2			(2.6	)%	315.3			291.8			8.1	%
Depreciation and amortization expense	24.6			23.6			4.2	%	72.3			66.9			8.1	%
Taxes other than income taxes	10.0			10.8			(7.4	)%	32.6			32.9			(0.9	)%
Operating income	80.4			67.8			18.6	%	164.8			159.2			3.5	%

Miscellaneous income	2.1			2.8			(25.0	)%	8.4			6.5			29.2	%
Interest expense	11.4			7.9			44.3	%	33.5			23.8			40.8	%
Other expense	(9.3		)	(5.1		)	82.4	%	(25.1		)	(17.3		)	45.1	%

Income before taxes	$	71.1		$	62.7		13.4	%	$	139.7		$	141.9		(1.6	)%

Sales in kilowatt-hours
Residential	710.4			775.0			(8.3	)%	2,156.7			2,157.5			—	%
Commercial and industrial	2,053.9			2,094.6			(1.9	)%	5,980.1			5,977.8			—	%
Wholesale	915.1			1,218.3			(24.9	)%	2,516.1			3,610.1			(30.3	)%
Other	7.0			7.0			—	%	22.8			22.9			(0.4	)%
Total sales in kilowatt-hours	3,686.4			4,094.9			(10.0	)%	10,675.7			11,768.3			(9.3	)%

Weather
Actual heating degree days	243			216			12.5	%	5,778			5,126			12.7	%
Normal heating degree days	210			216			(2.8	)%	4,831			4,837			(0.1	)%
Actual cooling degree days	224			396			(43.4	)%	333			527			(36.8	)%
Normal cooling degree days	364			361			0.8	%	505			498			1.4	%

Electric utility margins are defined as electric utility 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 utility 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 2014 Compared with Third Quarter 2013

Margins

Electric utility segment margins increased $10.2 million.


•	Margins increased approximately $9 million related to our PSCW rate order, effective January 1, 2014. See Note 15, Regulatory Environment, for more information.

◦

Excluding the impacts from fuel and purchased power costs, our PSCW rate order resulted in an approximate $20 million increase in margins. The increase was driven by the costs to operate the Fox Energy Center, which were included in rates beginning in 2014. Although the PSCW approved an electric rate decrease, the rate decrease was driven by 2013 fuel cost over-collections and 2012 decoupling over-collections that are being refunded to customers in 2014 and have no impact on margins.

◦

Margins were negatively impacted approximately $9 million related to fuel and purchased power-related costs that are not included in the fuel rule recovery mechanism. During 2013, customer rates included recovery of estimated purchased power costs from the Fox Energy Center that exceeded actual purchased power costs because the acquisition of this plant in March 2014 was not anticipated in the 2013 rate case. This resulted in a negative quarter-over-quarter impact on margins in 2014, which was partially offset by decreased costs in 2014 associated with fly ash disposal.


◦	Margins were further decreased by approximately $2 million related to fuel and purchased power cost under-collections in 2014, compared with over-collections in 2013. Under the fuel rule, we can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.


•	An approximate $1 million increase in our wholesale margins driven by higher prices. Wholesale prices increased primarily due to the pass-through of increased generation costs to these customers.

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•

There was no material impact on margins related to sales volume variances. Margins decreased approximately $9 million, primarily driven by lower sales volumes related to cooler than normal weather as well as lower use per customer in the third quarter of 2014. This decrease was offset by the impact of the termination of our decoupling mechanism, effective January 1, 2014. See Note 15, Regulatory Environment, for more information.

Operating Income

Operating income at the regulated electric utility segment increased $12.6 million. The increase was driven by the $10.2 million increase in margins discussed above and a $2.4 million decrease in operating expenses.

The decrease in operating expenses was driven by:


•	A $5.1 million net decrease in employee benefit costs, including the impact of the prior year deferral of some of these costs.

◦

Employee benefit costs decreased $8.7 million in the third quarter of 2014. This decrease was partially driven by the remeasurement of certain other postretirement benefit plan obligations. See Note 10, Employee Benefit Plans, for more information. Continued funding of our pension plan and higher discount rates assumed in 2014 for both our pension and postretirement plans also contributed to the overall decrease in employee benefit costs.


◦	This decrease was partially offset by the quarter-over-quarter impact of a deferral of certain employee benefit costs in 2013, recorded in accordance with our PSCW rate order, and the related amortization in 2014. Together, these changes increased employee benefit costs by $3.6 million.

•

A $1.8 million decrease due to the quarter-over-quarter impact of the 2013 deferral of the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center. The 2013 PSCW rate order did not reflect this purchase or the related termination of a power purchase agreement. However, we did receive PSCW approval to defer ownership costs above or below our power purchase agreement expenses in 2013.

These decreases were partially offset by:


•	A $1.4 million increase in the amortization of a regulatory asset related to the fee paid for the early termination of the Fox Energy Center power purchase agreement. Recovery of the amortization was included in the new rates.


•	A $1.1 million increase in electric distribution expense related to electrical upgrades and distribution automation work for customers.


•	A $1.0 million increase in depreciation and amortization expense, mainly due to the completion of the installation of the scrubbers at the Columbia plant in April 2014.

Other Expense

Other expense increased $4.2 million. The primary driver was an increase in interest expense on long-term debt, driven by higher average outstanding long-term debt in the third quarter of 2014.

Nine Months 2014 Compared with Nine Months 2013

Margins

Electric utility segment margins increased $34.2 million, driven by:


•	An approximate $31 million increase in margins related to our PSCW rate order, effective January 1, 2014. See Note 15, Regulatory Environment, for more information.

◦

Excluding the impacts from fuel and purchased power costs, the PSCW rate order resulted in an approximate $56 million increase in margins. The increase was driven by the costs to operate the Fox Energy Center, which were included in rates beginning in 2014. Although the PSCW approved an electric rate decrease, the rate decrease was driven by 2013 fuel cost over-collections and 2012 decoupling over-collections that are being refunded to customers in 2014 and have no impact on margins.


◦	Margins were negatively impacted by approximately $16 million related to fuel and purchased power-related costs that are not included in the fuel rule recovery mechanism. During 2013, customer rates included recovery of estimated purchased power costs from the Fox Energy Center that exceeded actual purchased power costs because the acquisition of this plant in March 2014 was not

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anticipated in the 2013 rate case. This resulted in a negative period-over-period impact on margins in 2014, which was partially offset by decreased costs in 2014 associated with fly ash disposal.


◦	Margins were further decreased by approximately $9 million related to fuel and purchased power cost under-collections in 2014, compared with over-collections in 2013. Under the fuel rule, we can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.


•	An approximate $6 million increase in wholesale margins driven by higher prices. Wholesale prices increased primarily due to the pass-through of increased generation costs to these customers, partially a result of the purchase of the Fox Energy Center in 2013.

•

A partially offsetting decrease in margins of approximately $3 million related to sales volume variances. The decrease in margins was primarily driven by lower sales volumes from both our large commercial and industrial customers as well as our residential customers. The decrease in these sales volumes was driven by lower use per customer in 2014. This decrease was partially offset by the impact of the termination of our decoupling mechanism, effective January 1, 2014. See Note 15, Regulatory Environment, for more information. Our decoupling mechanism did not cover large commercial and industrial customers.

Operating Income

Operating income at the regulated electric utility segment increased $5.6 million. The increase was driven by the $34.2 million increase in margins discussed above, partially offset by a $28.6 million increase in operating expenses.

The increase in operating expenses was driven by:


•	A $22.7 million increase in maintenance expense, primarily due to planned major outages in 2014 at the Pulliam plant, Fox Energy Center, and Weston 4, as well as maintenance at certain other generation plants. These increases were partially offset by the period-over-period impact of maintenance expenses associated with the Weston 3 planned major outage in 2013.


•	A $5.4 million increase in depreciation and amortization expense, mainly due to the acquisition of the Fox Energy Center at the end of the first quarter of 2013. In addition, we completed the installation of scrubbers at the Columbia plant in April 2014.


•	A $4.9 million increase in various costs associated with the acquisition and operation of the Fox Energy Center. Included in this amount is the amortization of a regulatory asset related to the fee paid for the early termination of the Fox Energy Center power purchase agreement. Recovery of the amortization was included in the new rates.


•	A $4.3 million increase in electric transmission expense.


•	A $2.1 million increase in amortization of the deferral of previously recorded production tax credits related to the Crane Creek wind project.

These increases were partially offset by:

•

A $7.2 million net decrease in employee benefit costs, including the impact of the prior year deferral of some of these costs. Employee benefit costs other than stock-based compensation (discussed below) decreased $19.8 million in 2014. This decrease was partially driven by the remeasurement of certain other postretirement benefit plan obligations. See Note 10, Employee Benefit Plans, for more information. Continued funding of our pension plan and higher discount rates assumed in 2014 for both our pension and postretirement plans also contributed to the overall decrease in employee benefit costs. This decrease was partially offset by:


◦	Higher stock-based compensation expense of $1.7 million, which was driven by an increase in the fair value of awards accounted for as liabilities. The increase in fair value resulted from an increase in Integrys Energy Group's stock price.


◦	The period-over-period impact of a deferral of certain increases in employee benefit costs in 2013, recorded in accordance with our PSCW rate order, and the related amortization in 2014. Together, these changes increased employee benefit costs by $10.9 million.

•

A $5.1 million decrease due to the period-over-period impact of the 2013 deferral of the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center. The 2013 PSCW rate order did not reflect this purchase or the related termination of a power purchase agreement. However, we did receive PSCW approval to defer ownership costs above or below our power purchase agreement expenses in 2013.

Other Expense

Other expense increased $7.8 million. The primary driver was an $11.7 million increase in interest expense on long-term debt, driven by higher average outstanding long-term debt in 2014. An increase in AFUDC of $2.8 million, largely due to the construction of the ReACT^TMemission control technology at the Weston 3 plant, partially offset the increase in interest expense.

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Natural Gas Utility Segment Operations



	Three Months Ended September 30						Change in 2014 Over 2013		Nine Months Ended September 30						Change in 2014 Over 2013
(Millions, except degree days)	2014			2013			Change in 2014 Over 2013		2014			2013			Change in 2014 Over 2013
Revenues	$	46.4		$	44.3		4.7	%	$	355.2		$	235.4		50.9	%
Natural gas purchased for resale	27.7			26.3			5.3	%	251.4			142.0			77.0	%
Margins	18.7			18.0			3.9	%	103.8			93.4			11.1	%

Operating and maintenance expense	16.2			15.8			2.5	%	51.1			48.0			6.5	%
Depreciation and amortization expense	4.1			3.9			5.1	%	12.2			11.8			3.4	%
Taxes other than income taxes	1.1			1.1			—	%	3.7			3.6			2.8	%
Operating income (loss)	(2.7		)	(2.8		)	(3.6	)%	36.8			30.0			22.7	%

Miscellaneous income	—			—			N/A		0.1			0.1			—	%
Interest expense	2.6			2.1			23.8	%	7.8			6.4			21.9	%
Other expense	(2.6		)	(2.1		)	23.8	%	(7.7		)	(6.3		)	22.2	%

Income before taxes	$	(5.3	)	$	(4.9	)	8.2	%	$	29.1		$	23.7		22.8	%

Retail throughput in therms
Residential	15.3			14.1			8.5	%	197.1			173.4			13.7	%
Commercial and industrial	14.3			15.8			(9.5	)%	126.4			107.4			17.7	%
Other	6.9			11.8			(41.5	)%	21.5			23.0			(6.5	)%
Total retail throughput in therms	36.5			41.7			(12.5	)%	345.0			303.8			13.6	%

Transport throughput in therms
Commercial and industrial	69.8			68.3			2.2	%	270.4			260.8			3.7	%

Total throughput in therms	106.3			110.0			(3.4	)%	615.4			564.6			9.0	%

Weather
Actual heating degree days	243			216			12.5	%	5,778			5,126			12.7	%
Normal heating degree days	210			216			(2.8	)%	4,831			4,837			(0.1	)%

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 20% and 56% increase in the average per-unit cost of natural gas sold during the three and nine months ended September 30, 2014, respectively, which had no impact on margins.

Third Quarter 2014 Compared with Third Quarter 2013

Margins

Natural gas utility segment margins increased $0.7 million, driven by the approximate $1 million combined effect of an increase in sales volumes due to higher use per customer, an increase in customers, and weather, partially offset by the impact of our decoupling mechanism in 2013. Our rate order, effective January 1, 2014, did not have a significant impact on margins quarter over quarter. The rate decrease was offset by the positive impact of rate design changes. Although the PSCW approved a net rate increase, it was driven by the recovery of the 2012 decoupling under-collections to be recovered from customers in 2014, which has no impact on margins.

Operating Loss

Operating loss at the natural gas utility segment decreased $0.1 million. This decrease was driven by the $0.7 million increase in margins discussed above, partially offset by a $0.6 million increase in operating expenses.

There were no individually significant items that impacted operating expenses.

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Nine Months 2014 Compared with Nine Months 2013

Margins

Natural gas utility segment margins increased $10.4 million.

•

The combined effect of the change in weather period over period, the impact of higher weather-normalized volumes, and the impact of our decoupling mechanism increased margins approximately $15 million. In 2014, our margins were positively impacted by colder than normal weather as we no longer had a decoupling mechanism in place, effective January 1, 2014. Higher use per customer and an increase in customers also contributed to the increase in margins in 2014.

•

Margins were negatively impacted by approximately $3 million related to our rate order, effective January 1, 2014. Although the PSCW approved a net rate increase, it was driven by the recovery of the 2012 decoupling under-collections to be recovered from customers in 2014, which has no impact on margins. The remaining decrease was partially offset by the positive impact of rate design changes. See Note 15, Regulatory Environment, for more information.

Operating Income

Operating income at the natural gas utility segment increased $6.8 million. This increase was driven by the $10.4 million increase in margins discussed above, partially offset by a $3.6 million increase in operating expenses.

The increase in operating expenses was primarily due to:


•	A $2.6 million increase in natural gas distribution costs, partially driven by safety inspections performed during 2014. Additional meter maintenance and higher labor costs related to wage increases also contributed to the increase in costs.


•	A $1.1 million increase in bad debt expense, driven by higher natural gas costs in 2014 and an increase in sales volumes.


•	A $1.0 million increase driven by higher amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites.

The increase in operating expenses was partially offset by:


•	A $1.5 million decrease in customer assistance expense, primarily driven by a reduction in costs for energy efficiency programs.


•	A $1.3 million decrease in employee benefit costs, primarily due to:


◦	A $5.1 million decrease in pension and other postretirement costs, driven in part by higher discount rates assumed in 2014. The remeasurement of certain postretirement benefit plans in the first quarter of 2014 also contributed to the decrease. See Note 10, Employee Benefit Plans, for more information on this remeasurement.

◦

This decrease in pension and other postretirement costs was partially offset by the $3.2 million negative period-over-period impact of the deferral of employee benefit costs in 2013 and the related amortization in 2014. In 2013, we deferred certain increases in pension and other employee benefit costs as a result of our 2013 rate order with the PSCW. We began amortizing this regulatory asset in 2014.

There were no other individually significant items that impacted operating expenses.

Other Segment Operations



	Three Months Ended September 30				Change in 2014 Over 2013		Nine Months Ended September 30				Change in 2014 Over 2013
(Millions)	2014		2013		Change in 2014 Over 2013		2014		2013		Change in 2014 Over 2013
Operating income	$	0.2	$	0.2	—	%	$	0.4	$	0.3	33.3	%
Other income	2.9		2.5		16.0	%	9.4		8.6		9.3	%
Income before taxes	$	3.1	$	2.7	14.8	%	$	9.8	$	8.9	10.1	%

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

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Provision for Income Taxes



	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Effective tax rate	37.7	%	37.7	%	37.3	%	37.1	%

There was no material change in our effective tax rate for all periods presented.

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, 2014, net cash provided by operating activities was $228.0 million, compared with $212.3 million during the same period in 2013. The $15.7 million increase in net cash provided by operating activities was driven by:


•	An $89.7 million increase in cash collections from customers, mainly due to rate increases, higher commodity prices, and the colder than normal weather in 2014.


•	The positive period-over-period impact of 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 $2.7 million increase in cash received from income taxes, primarily driven by a federal income tax refund received in the first quarter of 2014 for an amended return. Quarterly income tax estimate payments and a federal income tax extension payment made in 2014 partially offset the tax refund received.

These increases in cash were partially offset by:

•

A $79.5 million decrease in cash due to higher costs of natural gas, fuel, and purchased power in 2014. Additional cash was used in 2014 due to higher energy prices, the colder than normal weather, and for energy costs associated with operating the Fox Energy Center, which we acquired at the end of the first quarter of 2013. To meet the higher energy needs of customers, we purchased power and fuel for electric generation at higher prices than expected in 2014, which were not yet reflected in the rates charged to our customers. This resulted in a period-over-period variance from natural gas, purchased power, and fuel cost under-collections from customers of $33.1 million. These under-collections were higher in 2014 than in 2013.


•	A $12.5 million decrease in cash related to increased operating and maintenance costs in 2014. The decrease was driven by higher electric utility maintenance and operating costs associated with the purchase of the Fox Energy Center in 2013.


•	An $8.6 million increase in contributions to pension and other postretirement benefit plans.


•	A $7.8 million decrease in cash from various deferrals, primarily for system support resource costs, pre-certification costs for a potential new natural gas combined cycle generating unit, and the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center.


•	A $5.2 million increase in cash paid for interest, primarily driven by higher average outstanding long-term debt in 2014 as compared with 2013.


•	A $3.5 million decrease in cash from insurance recoveries received in 2013 related to environmental remediation of manufactured gas plant sites.


•	A $2.0 million decrease in cash driven by higher collateral requirements in 2014 compared with 2013. Collateral requirements are based on forward natural gas and electricity prices and forward positions with counterparties.

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Investing Cash Flows

During the nine months ended September 30, 2014, net cash used for investing activities was $218.6 million, compared with $491.3 million during the same period in 2013. The $272.7 million decrease 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 3, Acquisition of Fox Energy Center, for more information regarding this purchase. Partially offsetting the decrease in net cash used was the period-over-period negative impact of the receipt of a $69.0 million Section 1603 Grant for the Crane Creek wind project in 2013 and a $50.1 million increase in cash used for other capital expenditures (discussed below).

Capital Expenditures

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



Reportable Segment (millions)	2014		2013		Change in 2014 Over 2013
Electric utility	$	189.4	$	537.8	$	(348.4	)
Natural gas utility	33.5		26.6		6.9
WPS consolidated	$	222.9	$	564.4	$	(341.5	)

The decrease in capital expenditures at the electric utility segment in 2014 compared with 2013 was primarily due to our purchase of Fox Energy Company LLC in 2013. Capital expenditures related to environmental compliance projects at the Columbia plant also decreased in 2014. Increased expenditures in 2014 related to the ReACT^TM project at Weston 3 and the System Modernization and Reliability project partially offset the decrease.

Financing Cash Flows

During the nine months ended September 30, 2014, net cash used for financing activities was $11.5 million, compared with net cash provided by financing activities of $278.9 million for the same period in 2013. The $290.4 million period-over-period change was driven by:


•	A $200.0 million decrease in borrowings under our term credit facility, which were used in 2013 to partially finance the acquisition of Fox Energy Company LLC.


•	A $160.0 million decrease in equity contributions from Integrys Energy Group, which were used to support the acquisition of Fox Energy Company LLC in 2013.

These decreases in cash were partially offset by the period-over-period impact of:


•	A $35.0 million return of capital to our parent in 2013.


•	A $22.0 million repayment of long-term debt in 2013.


•	An $18.4 million increase in net borrowings of commercial paper in 2014.

Significant Financing Activities

For information on short-term debt, see Note 7, Short-Term Debt and Lines of Credit.

There were no significant changes in long-term debt during 2014.

Credit Ratings

Our current credit ratings are listed in the table below:



Credit Ratings	Standard & Poor's	Moody's
Issuer credit rating	A-	A1
First mortgage bonds	N/A	Aa2
Senior secured debt	A	Aa2
Preferred stock	BBB	A3
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.

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On January 31, 2014, Moody's raised the following credit ratings. Our issuer rating was raised to "A1" from "A2," our first mortgage bonds rating was raised to "Aa2" from "Aa3," our senior secured debt rating was raised to "Aa2" from "Aa3," and our preferred stock rating was raised to "A3" from "Baa1." The upgrade in ratings reflects Moody's views of the regulatory provisions in Wisconsin that are consistent with a generally improving regulatory environment for electric and natural gas utilities in the United States.

Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of September 30, 2014, including those of our subsidiary:



			Payments Due By Period
(Millions)	Total Amounts Committed		2014		2015 to 2016		2017 to 2018		2019 and Later Years
Long-term debt principal and interest payments ⁽¹⁾	$	2,356.6	$	14.4	$	231.2	$	215.7	$	1,895.3
Operating lease obligations	16.3		0.1		1.6		1.4		13.2
Energy and transportation purchase obligations ⁽²⁾	1,324.5		46.8		316.2		237.2		724.3
Purchase orders ⁽³⁾	384.8		277.3		92.7		14.8		—
Pension and other postretirement funding obligations ⁽⁴⁾	8.1		3.0		5.1		—		—
Total contractual cash obligations	$	4,090.3	$	341.6	$	646.8	$	469.1	$	2,632.8


⁽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 2016.

The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $76.0 million at September 30, 2014, 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.

Capital Requirements

Projected capital expenditures by segment for 2014 through 2016, including amounts expended through September 30, 2014, are as follows:



(Millions)	2014		2015		2016		Total
Electric Utility
Distribution, transmission, and energy supply operations projects	$	133	$	137	$	131	$	401
Environmental projects *	150		135		105		390
Other projects	7		11		158		176

Natural Gas Utility
Distribution projects	36		30		37		103
Other projects	1		1		1		3
Total capital expenditures	$	327	$	314	$	432	$	1,073


*	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 strategies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage our liquidity and capital resource needs. We plan to meet our capital requirements for the period 2014 through 2016 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.

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We currently have a shelf registration statement under which we may issue up to $50.0 million of additional senior debt securities. Amounts, prices, and terms will be determined at the time of future offerings.

At September 30, 2014, 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.

Other Future Considerations

Presque Isle System Support Resources (SSR) Costs

In August 2013, Wisconsin Electric Power Company (Wisconsin Electric Power) submitted to MISO a notice, in which Wisconsin Electric Power stated its intention to suspend the operation of Units 5 through 9 of its Presque Isle generating facility for 16 months, starting February 1, 2014. MISO completed its reliability analysis and notified Wisconsin Electric Power in October 2013 that the Presque Isle facilities are required for reliability and would be SSR-designated until alternatives could be implemented to mitigate reliability issues. The SSR Tariff provisions permit MISO to negotiate compensation for generation resources when a market participant desires to retire or suspend operation of the facility but MISO determines that it is needed to maintain system reliability. In exchange for keeping the units in service, MISO compensates Wisconsin Electric Power by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load serving entities, including us, based on load ratio share within the ATC footprint. In July 2014, the FERC granted a complaint filed by the PSCW requesting to change the allocation methodology to the various parties based on a new load-shed analysis to be completed by MISO. In August 2014, MISO submitted a revised rate schedule to the FERC based on a new load-shed analysis, which reduced our allocated SSR costs from the original estimate of approximately $9 million annually to $0.3 million annually. Later in August 2014, the MPSC requested a rehearing of the FERC's decision to change the allocation methodology, which the PSCW is protesting.

In April 2013, the PSCW ordered that SSR costs for our retail customers should be deferred until December 31, 2015. At that time, the PSCW will determine the appropriate ratemaking treatment. As of September 30, 2014, there was no material SSR costs for retail customers deferred for future recovery. SSR costs for our Michigan customers are being recovered through the Power Supply Cost Recovery mechanism. SSR costs for our wholesale customers are being recovered through formula rates.

MISO Transmission Owner Return on Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting, among other things, to reduce the base return on equity (ROE) used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. However, the FERC denied all other aspects of the complaint, including that the use of capital structures that include more than 50% common equity is unjust and unreasonable. If the case does not settle, the FERC expects to issue a decision by August 31, 2016.

In October 2014, the FERC also issued an order, in regard to a similar complaint, to reduce the base ROE for New England transmission owners from their existing rate of 11.14% to 10.57%. The FERC used a revised method for determining the appropriate ROE for FERC-jurisdictional electric utilities, which incorporates both short-term and long-term measures of growth in dividends.

The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues will be guided by the New England transmission decision. Any change to ATC's return on equity and capital structure could result in lower equity income and dividends from ATC in the future. We are currently unable to determine the timing, financial impact, and nature of any FERC actions related to this complaint.

Wisconsin Fuel Rule Under-collection "Cap"

We use a "fuel window" mechanism to recover fuel and purchased power costs for our Wisconsin retail electric operations. Under the fuel window rule, actual fuel and purchased power costs that exceed a 2% variance from costs included in the rates charged to customers are deferred for recovery or refund. However, if the deferral of costs in a given year would cause us to earn a greater return on common equity than authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount the return exceeds the authorized amount by the PSCW. This is a possibility in any given year; however, this provision of the fuel rule will likely not have an impact on us in 2014.

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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. In September 2013, the EPA re-proposed rules related to emission limits on new electric generating units, and the EPA is expected to finalize them in a timely manner. The proposed emission rate limits may not be achievable for coal-fueled plants until applicable technology becomes commercially available. In June 2014, the EPA issued a proposed rule establishing greenhouse gas performance standards for modified and reconstructed power plants. Comments on this proposal were due in October 2014.

Also, in June 2014, the EPA released a proposed rule establishing greenhouse gas performance standards for existing power plants. The proposal applies to “affected electric generating units,” which includes our coal-fired units at Weston and Pulliam plus the natural gas-fired Fox Energy Center. The EPA is proposing state-specific emission reduction goals. States would be required to meet an “interim goal” on average over the ten-year period from 2020 through 2029 and a “final goal” in 2030, which will achieve a nation-wide emission reduction of about 30% from 2005 levels. In the proposed rule, the state of Wisconsin is assigned a relatively aggressive reduction goal, which if adopted as final, could significantly increase costs for our customers. Consequently, we are working with the other state utilities, the WDNR, the PSCW, and other stakeholders to evaluate the potential impacts and develop comments and suggested revisions for the EPA's consideration. The EPA intends to issue final rules by June 1, 2015. State implementation plans are due by June 30, 2016, with the possibility of extensions to 2017 for a state-specific plan and to 2018 if they are using a multistate approach. 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.

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 our derivatives, which 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 and have implemented the applicable requirements of the Dodd-Frank Act rules that have taken effect. For example, we have addressed certain requirements applicable to transaction reporting and have implemented an internal governance structure. We have also taken the necessary steps to qualify as an end user, which provides for an exemption related to mandatory clearing. Lastly, we have made the necessary systems and process changes to comply with the rules within the CFTC's implementation timelines.

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, 2013, 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 2013 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 our 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 our 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, 2014, 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

See Note 9, Commitments and Contingencies, for more information on material legal proceedings and matters related to us and our subsidiary.

Item 1A. Risk Factors

There were no material changes in the risk factors previously disclosed in Part I, Item 1A of our 2013 Annual Report on Form 10-K, which was filed with the SEC on February 28, 2014.

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. See Note 12, Common Equity, for more information on dividends paid and dividend restrictions.

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 5, 2014	/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, 2014



Exhibit No.		Description

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, 2014, 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

Attached files

WISCONSIN PUBLIC SERVICE CORP Reports

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