WISCONSIN PUBLIC SERVICE CORP - FORM 10-Q

WISCONSIN PUBLIC SERVICE CORP - FORM 10-Q - May 5, 2015

Attached files

Attached files

WISCONSIN PUBLIC SERVICE CORP Reports

file	filename
EX-31.2 - EXHIBIT 31.2 - WISCONSIN PUBLIC SERVICE CORP	a2015q1wps10-qexhibit312.htm
EX-32 - EXHIBIT 32 - WISCONSIN PUBLIC SERVICE CORP	a2015q1wps10-qexhibit32.htm
EXCEL - IDEA: XBRL DOCUMENT - WISCONSIN PUBLIC SERVICE CORP	Financial_Report.xls
EX-31.1 - EXHIBIT 31.1 - WISCONSIN PUBLIC SERVICE CORP	a2015q1wps10-qexhibit311.htm

Table of Contents

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 March 31, 2015

[ ] 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

May 4, 2015

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WISCONSIN PUBLIC SERVICE CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2015

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	Cash and Cash Equivalents	6
	Note 4	Goodwill and Other Intangible Assets	6
	Note 5	Short-Term Debt and Lines of Credit	7
	Note 6	Income Taxes	7
	Note 7	Commitments and Contingencies	7
	Note 8	Employee Benefit Plans	10
	Note 9	Stock-Based Compensation	10
	Note 10	Common Equity	12
	Note 11	Risk Management Activities	13
	Note 12	Fair Value	14
	Note 13	Miscellaneous Income	17
	Note 14	Regulatory Environment	17
	Note 15	Segments of Business	18
	Note 16	Related Party Transactions	18
	Note 17	New Accounting Pronouncements	19
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations			21
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			30
ITEM 4.	Controls and Procedures			31
PART II.	OTHER INFORMATION			32
ITEM 1.	Legal Proceedings			32
ITEM 1A.	Risk Factors			32
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			32
ITEM 6.	Exhibits			32
Signature				33
EXHIBIT INDEX				34

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Acronyms Used in this Quarterly Report on Form 10-Q



AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATC	American Transmission Company LLC
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	United States Generally Accepted Accounting Principles
IBS	Integrys Business Support, LLC
IES	Integrys Energy Services, Inc.
IRS	United States Internal Revenue Service
MISO	Midcontinent Independent System Operator, Inc.
MPSC	Michigan Public Service Commission
N/A	Not Applicable
NYMEX	New York Mercantile Exchange
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
UPPCO	Upper Peninsula Power Company
WDNR	Wisconsin Department of Natural Resources
WPS	Wisconsin Public Service Corporation
WRPC	Wisconsin River Power Company

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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, 2014, 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;


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


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


•	The 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;


•	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;


•	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 ability to retain market-based rate authority;


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


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


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


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


•	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
	March 31
(Millions)	2015			2014
Operating revenues	$	424.7		$	555.7

Cost of fuel, natural gas, and purchased power	205.2			305.8
Operating and maintenance expense	107.7			122.1
Depreciation and amortization expense	29.2			27.6
Taxes other than income taxes	12.5			12.6
Operating income	70.1			87.6

Miscellaneous income	6.6			7.3
Interest expense	13.9			14.0
Other expense	(7.3		)	(6.7		)

Income before taxes	62.8			80.9
Provision for income taxes	23.0			29.8
Net income	39.8			51.1

Preferred stock dividend requirements	(0.8		)	(0.8		)
Net income attributed to common shareholder	$	39.0		$	50.3

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

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WISCONSIN PUBLIC SERVICE CORPORATION



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	March 31		December 31
(Millions, except share and per share data)	2015		2014
Assets
Cash and cash equivalents	$	3.9	$	5.4
Accounts receivable and accrued unbilled revenues, net of reserves of $4.1 and $3.2, respectively	196.1		201.7
Receivables from related parties	1.4		1.3
Inventories
Fuel and gas	60.8		85.0
Materials and supplies, at average cost	42.9		39.2
Regulatory assets	24.1		25.0
Prepaid taxes	29.3		65.7
Other current assets	14.9		18.3
Current assets	373.4		441.6

Property, plant, and equipment, net of accumulated depreciation of $1,557.3 and $1,542.5, respectively	3,178.6		3,131.0
Regulatory assets	431.6		433.5
Goodwill	36.4		36.4
Pension and other postretirement benefit assets	134.8		128.9
Other long-term assets	112.7		107.3
Total assets	$	4,267.5	$	4,278.7

Liabilities and Shareholders’ Equity
Short-term debt	$	100.4	$	145.1
Current portion of long-term debt	125.0		125.0
Current portion of long-term debt to parent	0.5		2.5
Accounts payable	160.1		161.6
Payables to related parties	16.8		16.9
Regulatory liabilities	33.5		21.2
Other current liabilities	80.8		69.3
Current liabilities	517.1		541.6

Long-term debt to parent	2.8		2.9
Long-term debt	1,049.5		1,049.5
Deferred income taxes	731.5		722.1
Deferred investment tax credits	7.7		7.8
Regulatory liabilities	302.1		303.3
Environmental remediation liabilities	82.7		86.3
Pension and other postretirement benefit obligations	38.2		37.6
Payables to related parties	5.3		5.4
Other long-term liabilities	68.4		71.6
Long-term liabilities	2,288.2		2,286.5

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	783.5		782.0
Retained earnings	531.9		521.8
Total liabilities and shareholders’ equity	$	4,267.5	$	4,278.7

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)				March 31			December 31
(Millions, except share and per share data)				2015			2014
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				783.5			782.0
Retained earnings				531.9			521.8
Total common stock equity				1,411.0			1,399.4

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	—			2.0
	7.35	%	2016	3.3			3.4
Total				3.3			5.4
Current portion of long-term debt to parent				(0.5		)	(2.5		)
Total long-term debt to parent				2.8			2.9

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				1,174.5			1,174.5
Current portion of long-term debt				(125.0		)	(125.0		)
Total long-term debt				1,049.5			1,049.5
Total capitalization				$	2,514.5		$	2,503.0

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)	Three Months Ended
	March 31
(Millions)	2015			2014
Operating Activities
Net income	$	39.8		$	51.1
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	29.2			27.6
Recoveries and refunds of regulatory assets and liabilities	0.1			3.8
Pension and other postretirement contributions	(0.5		)	(46.2		)
Deferred income taxes and investment tax credits	10.1			14.7
Deferrals to regulatory assets and liabilities	(2.5		)	(13.5		)
Other	(9.8		)	(3.2		)
Changes in working capital
Accounts receivable and accrued unbilled revenues	3.6			(46.2		)
Inventories	20.2			28.0
Prepaid taxes	36.3			32.9
Other current assets	3.2			(1.3		)
Accounts payable	(1.5		)	33.6
Other current liabilities	24.8			15.1
Net cash provided by operating activities	153.0			96.4

Investing Activities
Capital expenditures	(79.8		)	(58.8		)
Other	1.4			0.6
Net cash used for investing activities	(78.4		)	(58.2		)

Financing Activities
Short-term debt, net	(44.7		)	(7.4		)
Repayment of long-term debt to parent	(2.1		)	(0.2		)
Payment of dividends to parent	(28.8		)	(28.0		)
Preferred stock dividend requirements	(0.8		)	(0.8		)
Other	0.3			(0.1		)
Net cash used for financing activities	(76.1		)	(36.5		)

Net change in cash and cash equivalents	(1.5		)	1.7
Cash and cash equivalents at beginning of period	5.4			5.7
Cash and cash equivalents at end of period	$	3.9		$	7.4

Cash paid for interest	$	0.2		$	0.1
Cash received for income taxes	$	(18.5	)	$	(15.0	)

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)

March 31, 2015

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, 2014. 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.

Reclassifications

We reclassified $17.9 million on the statement of cash flows for the three months ended March 31, 2014, from the recoveries and refunds of regulatory assets and liabilities line item to the other current liabilities line item. This reclassification had no impact on total cash flows from operating activities.

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 was also approved by the shareholders of both companies. In October 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. In April 2015, the transaction was approved by the Federal Communications Commission, the FERC, and the MPSC. On April 30, 2015, the transaction was verbally approved by the PSCW subject to certain conditions. A final written order is expected from the PSCW in May 2015. The transaction is still subject to approvals from the Illinois Commerce Commission (ICC) and the Minnesota Public Utilities Commission, as well as other customary closing conditions. We expect the merger transaction to close by the end of this summer.

Note 3—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 $49.1 million at March 31, 2015, and $35.0 million at March 31, 2014. These costs were treated as noncash investing activities.

Note 4—Goodwill and Other Intangible Assets

We had no changes to the carrying amount of goodwill during the three months ended March 31, 2015, and 2014.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets.



	March 31, 2015							December 31, 2014
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Contractual service agreements ⁽¹⁾	$	15.6	$	(5.1	)	$	10.5	$	15.6	$	(4.3	)	$	11.3
Other ⁽²⁾	0.4		—			0.4		—		—			—
Total intangible assets	$	16.0	$	(5.1	)	$	10.9	$	15.6	$	(4.3	)	$	11.3


⁽¹⁾	Represents 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. The remaining weighted-average amortization period for these intangible assets at March 31, 2015, was approximately four years.


⁽²⁾	Consists of an unamortized intangible asset.

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The table below shows the amortization we recorded:



	Three Months Ended March 31
(Millions)	2015		2014
Amortization recorded in depreciation and amortization expense	$	0.5	$	0.6
Amortization recorded in regulatory assets	0.3		—

The following table shows our estimated amortization for the next five years, including amounts recorded through March 31, 2015:



	For the Year Ending December 31
(Millions)	2015		2016		2017		2018		2019
Amortization to be recorded in depreciation and amortization expense	$	2.2	$	2.2	$	1.7	$	1.2	$	1.2
Amortization to be recorded in regulatory assets	1.0		1.0		0.5		—		—

Note 5—Short-Term Debt and Lines of Credit

Our outstanding short-term borrowings were as follows:



(Millions, except percentages)	March 31, 2015				December 31, 2014
Commercial paper	$	100.4		*	$	145.1
Average interest rate on commercial paper outstanding	0.32		%		0.32		%


*	Maturity dates ranged from April 1, 2015, through April 14, 2015.

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2015, and 2014, was $116.5 million and $9.1 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	March 31, 2015		December 31, 2014
Revolving credit facility	05/08/2019	$	135.0	$	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		100.4		145.1
Available capacity under existing agreements		$	149.6	$	104.9

Note 6—Income Taxes

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

The table below shows our effective tax rates:

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 months ended March 31, 2015, and 2014.

We had no liabilities for unrecognized tax benefits at March 31, 2015, and December 31, 2014.

Note 7—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.

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The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2015:



				Payments Due By Period
(Millions)	Year Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
Electric utility
Purchased power	2029	$	806.1	$	92.1	$	42.7	$	53.3	$	55.9	$	57.1	$	505.0
Coal supply and transportation	2019	155.8		44.3		34.8		33.5		32.1		11.1		—
Natural gas utility supply and transportation	2024	229.1		31.3		43.4		42.9		42.4		27.1		42.0
Total		$	1,191.0	$	167.7	$	120.9	$	129.7	$	130.4	$	95.3	$	547.0

(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, which alleged 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™, at 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. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023.

We received approval from the PSCW in our 2014 and 2015 rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that additional prudently incurred costs after 2015 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 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 March 31, 2015. 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 alleged 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.

The Consent Decree contains a requirement to refuel, repower, or retire Edgewater 4, of which we are a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that the Edgewater 4 unit be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.

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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 challenged 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 February 2014, we also requested a modification to the construction permit for Weston 4 to remove the mercury Best Available Control Technology (BACT) emission limit requirement. This permit request was denied by the WDNR, and we challenged this issue as well. At our request, the permit was modified to resolve several of the petition issues. Those issues have now been voluntarily dismissed from the case, while a new permit change was challenged and added to the case. The administrative law judge (ALJ) recently dismissed some of the petition issues relating to the averaging period and monitoring issues.

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. The WDNR also issued a Notice of Inquiry (NOI) alleging that we failed to comply with reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied our request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV and NOI. The contested case is proceeding and certain legal arguments are currently being addressed in the context of summary judgment motions. No hearing date has been set.

We do not expect these matters to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury and Other Hazardous Air Pollutants:

In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which regulates emissions of mercury and other hazardous air pollutants beginning in April 2015. The State of Wisconsin recently revised the compliance dates in 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. We placed in service capital projects for our wholly owned plants in 2015 to achieve the required reductions for MATS compliance in April 2015. These 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 October 2014, the Court of Appeals granted the EPA's request to lift the stay on CSAPR and changed the compliance deadlines by three years, so that Phase I emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond. We do not expect to incur significant costs to comply with either phase of CSAPR and 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.

Clean Water Act Rule

In August 2014, the EPA issued a final Clean Water Act rule, which established requirements under Section 316(b) to regulate water intake structures at industrial facilities that use large volumes of surface water as cooling water. The new rule became effective in October 2014 and has been challenged by a number of parties. The cases have been consolidated and will be heard in the United States Court of Appeals for the Second Circuit. To the extent that the rule is upheld, we will comply with the rule on the timeline required under the regulation. We will evaluate the impact of compliance by conducting the studies required by the rule at our facilities. We anticipate that the timing for compliance will be incorporated into future wastewater discharge permit renewals. We do not expect to incur significant costs to comply with the Clean Water Act rule at our Weston plant as this plant already has two units equipped with cooling towers that assist with meeting these new requirements. We expect to recover any future compliance costs in future rates.

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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 sheet includes liabilities of $82.7 million that we have estimated and accrued for as of March 31, 2015, 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 March 31, 2015, cash expenditures for environmental remediation not yet recovered in rates were $18.7 million. Our balance sheet also includes a regulatory asset of $101.4 million at March 31, 2015, 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.

Note 8—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 March 31						Three Months Ended March 31
(Millions)	2015			2014			2015			2014
Service cost	$	2.7		$	2.4		$	2.2		$	2.5
Interest cost	8.0			8.7			2.6			3.9
Expected return on plan assets	(16.4		)	(16.2		)	(4.0		)	(4.6		)
Loss on plan settlement	0.1			—			—			—
Amortization of prior service cost (credit)	—			0.1			(2.3		)	(1.1		)
Amortization of net actuarial loss	4.9			3.7			1.0			0.6
Net periodic benefit (credit) cost	$	(0.7	)	$	(1.3	)	$	(0.5	)	$	1.3

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 as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 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 three months ended March 31, 2015, we contributed $0.4 million to our pension plans and $0.1 million to our other postretirement benefit plans. We expect to contribute an additional $0.8 million to our pension plans and $1.3 million to our other postretirement benefit plans during the remainder of 2015, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Note 9—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.

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The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the three months ended March 31:



	Three months ended March 31
(Millions)	2015		2014
Stock options	$	—	$	0.1
Performance stock rights	0.2		0.2
Restricted share units	1.4		1.0
Total stock-based compensation expense	$	1.6	$	1.3
Deferred income tax benefit	$	0.6	$	0.5

No stock-based compensation cost was capitalized during the three months ended March 31, 2015, and 2014.

Stock Options

The weighted-average fair value per stock option granted during the three months ended March 31, 2014, was $6.70. No stock options were granted during 2015.

There were no changes to stock options outstanding during the three months ended March 31, 2015. Information related to outstanding and exercisable stock options at March 31, 2015, is presented below:



	Stock Options	Weighted-Average Exercise Price Per Share		Weighted-Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at March 31, 2015	5,714	$	54.18	7.3	$	0.1
Exercisable at March 31, 2015	2,752	$	53.13	6.9	$	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 March 31, 2015. This is calculated as the difference between Integrys Energy Group’s closing stock price on March 31, 2015, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the three months ended March 31, 2014, was not significant. No stock options were exercised during 2015.

Due to the accelerated vesting of all unvested stock options held by active employees in October 2014, all compensation expense related to outstanding stock options has been recognized.

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 two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31, 2015:



Risk-free interest rate		0.42% – 0.63%
Expected dividend yield		5.25% – 5.33%
Expected volatility		18% – 19%

A summary of the activity for the three months ended March 31, 2015, related to performance stock rights accounted for as equity awards is presented below:



	Performance Stock Rights		Weighted-Average Fair Value *
Outstanding at December 31, 2014	3,903		$	58.03
Distributed	(2,028	)	78.09
Adjustment for final payout	612		78.09
Outstanding at March 31, 2015	2,487		$	46.61


*	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 three months ended March 31, 2014, was $44.28 per performance stock right. No performance stock rights were granted during 2015.

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A summary of the activity for the three months ended March 31, 2015, related to performance stock rights accounted for as liability awards is presented below:



	Performance Stock Rights
Outstanding at December 31, 2014	10,034
Distributed	(201	)
Adjustment for final payout	96
Outstanding at March 31, 2015	9,929

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2015, was $107.05 per performance stock right.

The total intrinsic value of shares distributed during the three months ended March 15, 2015, was not significant. No shares of Integrys Energy Group's common stock were distributed for performance stock rights during the three months ended March 31, 2014, because the performance percentage was below the threshold payout level for those rights that were eligible for distribution.

As of March 31, 2015, $1.6 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 three months ended March 31, 2015, is presented below:



	Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2014	70,544		$	54.46
Granted	30,174		77.17
Dividend equivalents	665		64.30
Vested and released	(28,292	)	53.41
Transfers	231		55.91
Outstanding at March 31, 2015	73,322		$	64.30

The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2015, and 2014, was $77.17 and $55.23 per unit, respectively.

The total intrinsic value of restricted share unit awards vested and released during the three months ended March 31, 2015, and 2014, was

$2.2 million and $1.5 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the three months ended March 31, 2015, and 2014, was not significant.

As of March 31, 2015, $9.3 million of compensation cost related to unvested and outstanding restricted share units was expected to be recognized over a weighted-average period of 2.6 years.

Note 10—Common Equity

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

The PSCW allows us to pay dividends on our common stock of no more than 103% of the previous year's common stock dividend. We may return capital to Integrys Energy Group if our average financial common equity ratio is at least 51% on a calendar year basis. We must obtain PSCW approval if a return of capital would cause our average financial common equity ratio to fall below this level. Integrys Energy Group's right to receive dividends on our common stock is also subject to the prior rights of our preferred shareholders and to provisions in our restated articles of 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 March 31, 2015, our total restricted retained earnings were $528.9 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $31.9 million at March 31, 2015.

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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 three months ended March 31, 2015, we paid common stock dividends of $28.8 million to Integrys Energy Group.

Note 11—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:



		March 31, 2015
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other current	$	0.1	$	1.5
FTRs	Other current	0.7		0.1
Petroleum product contracts	Other current	—		0.8
Coal contracts	Other current	—		4.3
Coal contracts	Other long-term	—		3.1
	Other current	0.8		6.7
	Other long-term	—		3.1
Total		$	0.8	$	9.8


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



		December 31, 2014
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other current	$	0.1	$	2.1
Natural gas contracts	Other long-term	—		0.1
FTRs	Other current	2.2		0.3
Petroleum product contracts	Other current	—		1.1
Coal contracts	Other current	—		2.4
Coal contracts	Other long-term	—		1.0
	Other current	2.3		5.9
	Other long-term	—		1.1
Total		$	2.3	$	7.0


*	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:



	March 31, 2015
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	0.8	$	0.2	$	0.6
Derivative assets not subject to master netting or similar arrangements	—				—
Total risk management assets	$	0.8			$	0.6

Derivative liabilities subject to master netting or similar arrangements	$	2.4	$	2.4	$	—
Derivative liabilities not subject to master netting or similar arrangements	7.4				7.4
Total risk management liabilities	$	9.8			$	7.4

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	December 31, 2014
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	2.3	$	0.4	$	1.9
Derivative assets not subject to master netting or similar arrangements	—				—
Total risk management assets	$	2.3			$	1.9

Derivative liabilities subject to master netting or similar arrangements	$	3.6	$	3.6	$	—
Derivative liabilities not subject to master netting or similar arrangements	3.4				3.4
Total risk management liabilities	$	7.0			$	3.4

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 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)	March 31, 2015		December 31, 2014
Cash collateral provided to others related to contracts under master netting or similar arrangements *	$	5.9	$	6.6


*	Cash collateral provided to others is reflected in other current assets on the balance sheets.

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



		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2015			2014
Natural gas	Balance Sheet — Regulatory assets (current)	$	0.9		$	0.2
Natural gas	Balance Sheet — Regulatory liabilities (current)	(0.1		)	0.1
FTRs	Balance Sheet — Regulatory assets (current)	0.2			0.1
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.4		)	(0.1		)
Petroleum	Balance Sheet — Regulatory assets (current)	0.4			—
Coal	Balance Sheet — Regulatory assets (current)	(2.6		)	0.2
Coal	Balance Sheet — Regulatory assets (long-term)	(2.0		)	0.4
Coal	Balance Sheet — Regulatory liabilities (long-term)	—			1.6

We had the following notional volumes of outstanding derivative contracts:

(Millions)

March 31, 2015

December 31, 2014

Commodity

Purchases

Other Transactions

Purchases

Other Transactions

Natural gas (therms)

53.4

N/A

1,025.4

N/A

FTRs (kilowatt-hours)

N/A

2,111.1

N/A

4,287.7

Petroleum products (barrels)

0.1

N/A

—

N/A

Coal contract (tons)

2.6

N/A

3.0

N/A

Note 12—Fair Value

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.

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.

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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 methods.

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.

Our risk management assets and liabilities include NYMEX futures and options, physical commodity contracts, and financial transmission rights (FTRs) used to manage transmission congestion costs in the MISO market. When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. The valuations for certain physical coal contracts are categorized as Level 3 as they are based on significant assumptions made to extrapolate prices from the last quoted period through the end of the transaction term. The valuation for FTRs is derived from historical data from MISO, which is also considered a Level 3 input. See Note 11, Risk Management Activities, for more information.

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 supply 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.

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:



	March 31, 2015
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
Financial transmission rights (FTRs)	—		—		0.7		0.7
Total	$	0.1	$	—	$	0.7	$	0.8

Risk management liabilities
Natural gas contracts	$	1.5	$	—	$	—	$	1.5
FTRs	—		—		0.1		0.1
Petroleum product contracts	0.8		—		—		0.8
Coal contracts	—		1.2		6.2		7.4
Total	$	2.3	$	1.2	$	6.3	$	9.8



	December 31, 2014
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	—	$	0.1	$	—	$	0.1
FTRs	—		—		2.2		2.2
Total	$	—	$	0.1	$	2.2	$	2.3

Risk management liabilities
Natural gas contracts	$	2.2	$	—	$	—	$	2.2
FTRs	—		—		0.3		0.3
Petroleum product contracts	1.1		—		—		1.1
Coal contracts	—		1.2		2.2		3.4
Total	$	3.3	$	1.2	$	2.5	$	7.0

There were no transfers between the levels of the fair value hierarchy during the three months ended March 31, 2015, and 2014.

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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 March 31, 2015:

Fair Value (Millions)

Assets

Liabilities

Valuation Technique

Unobservable Input

Average or Range

FTRs

0.7

0.1

Market-based

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

$159.42

Coal contracts

—

6.2

Market-based

Forward market prices ($/ton) ⁽²⁾

$9.70 – $12.39


⁽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 or forward coal prices would result in a directionally similar significant change in fair value.

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



	Three Months Ended March 31, 2015
(Millions)	FTRs			Coal Contracts			Total
Balance at the beginning of period	$	1.9		$	(2.2	)	$	(0.3	)
Net realized losses included in earnings	(1.2		)	—			(1.2		)
Net unrealized losses recorded as regulatory assets or liabilities	(0.2		)	(4.3		)	(4.5		)
Settlements	0.1			0.3			0.4
Balance at the end of period	$	0.6		$	(6.2	)	$	(5.6	)

	Three Months Ended March 31, 2014
(Millions)	FTRs			Coal Contracts			Total
Balance at the beginning of period	$	1.2		$	(2.5	)	$	(1.3	)
Net realized gains included in earnings	0.7			—			0.7
Net unrealized gains recorded as regulatory assets or liabilities	—			2.2			2.2
Purchases	(0.1		)	—			(0.1		)
Settlements	(1.3		)	0.6			(0.7		)
Balance at the end of period	$	0.5		$	0.3		$	0.8

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:



	March 31, 2015				December 31, 2014
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	1,174.5	$	1,318.8	$	1,174.5	$	1,286.2
Long-term debt to parent	3.3		3.5		5.4		5.7
Preferred stock	51.2		52.5		51.2		52.0

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.

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Note 13—Miscellaneous Income

Total miscellaneous income was as follows:



	Three Months Ended March 31
(Millions)	2015		2014
Equity portion of AFUDC	$	2.9	$	3.6
Earnings from equity method investments	2.6		2.8
Key executive life insurance for retired employees	0.9		0.7
Other	0.2		0.2
Total miscellaneous income	$	6.6	$	7.3

Note 14—Regulatory Environment

Wisconsin

2016 Rate Case

In April 2015, we filed an application with the PSCW to increase retail electric rates $94.1 million and increase retail natural gas rates $9.4 million, with rates expected to be effective January 1, 2016. Our request reflects a 10.20% return on common equity and a target common equity ratio of 50.52% in our regulatory capital structure. The proposed retail electric rate increase is primarily driven by the 2016 expected completion of the ReACT™ emission control technology at Weston 3, the System Modernization and Reliability Project, and technology upgrades at the Fox Energy Center. Also included are increases in expenses for electric transmission, customer service, other operating and maintenance, and general inflation. The proposed retail natural gas rate increase is driven by the expiration of a 2015 customer refund related to decoupling, increased operating and maintenance costs, and general inflation.

2015 Rates

In December 2014, the PSCW issued a final written order, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.28% in our regulatory capital structure. The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service.

The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42 million. In addition, 2015 rates include approximately $9 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we are refunding approximately $4 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, we would have realized an electric rate decrease. In addition, we received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. See Note 7, Commitments and Contingencies, for more information. The PSCW is allowing us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent tolerance window.

The retail natural gas rate decrease was driven by the approximate $16 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we are refunding approximately $8 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, we would have realized a retail natural gas increase.

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, 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 of approximately $8 million 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. 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 for the Pulliam and Weston sites. See Note 7, Commitments and Contingencies, for more information. Additionally, the order required us to terminate our decoupling mechanism, beginning January 1, 2014.

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Michigan

2015 Rates

In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement between us and all parties. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for 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 generation plants. The rates reflect a 10.20% return on common equity and a target common equity ratio of 50.48% in our regulatory capital structure. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston 3 ReACT™ environmental project costs. On the second anniversary of the order, we will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. We also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. Lastly, we will not seek to increase retail electric base rates prior to January 1, 2018.

Note 15—Segments of Business

At March 31, 2015, 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.

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 March 31, 2015
External revenues	$	295.8		$	128.9		$	424.7		$	—	$	—		$	424.7
Intersegment revenues	—			2.6			2.6			0.2		(2.8		)	—
Depreciation and amortization expense	25.0			4.2			29.2			0.1		(0.1		)	29.2
Miscellaneous income	2.8			0.1			2.9			3.7		—			6.6
Interest expense	10.9			2.6			13.5			0.4		—			13.9
Provision for income taxes	16.4			5.6			22.0			1.0		—			23.0
Preferred stock dividend requirements	(0.7		)	(0.1		)	(0.8		)	—		—			(0.8		)
Net income attributed to common shareholder	27.9			8.9			36.8			2.2		—			39.0

	Regulated Utilities
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Three Months Ended March 31, 2014
External revenues	$	321.4		$	234.3		$	555.7		$	—	$	—		$	555.7
Intersegment revenues	—			4.4			4.4			0.3		(4.7		)	—
Depreciation and amortization expense	23.5			4.0			27.5			0.2		(0.1		)	27.6
Miscellaneous income	3.5			—			3.5			3.8		—			7.3
Interest expense	10.9			2.6			13.5			0.5		—			14.0
Provision for income taxes	15.5			13.3			28.8			1.0		—			29.8
Preferred stock dividend requirements	(0.7		)	(0.1		)	(0.8		)	—		—			(0.8		)
Net income attributed to common shareholder	27.2			20.7			47.9			2.4		—			50.3

Note 16—Related Party Transactions

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

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

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

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



(Millions)	March 31, 2015		December 31, 2014
Notes payable *
Integrys Energy Group	$	3.3	$	5.4
Accounts Payable
ATC	8.4		8.2
Liability related to income tax allocation
Integrys Energy Group	5.9		6.1


*	WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group. At March 31, 2015, and December 31, 2014, the current portion of the note payable was $0.5 million and $2.5 million, respectively.

The following table shows activity associated with related party transactions:



	Three Months Ended March 31
(Millions)	2015		2014
Electric transactions
Sales to UPPCO ⁽¹⁾	$	—	$	5.4
Natural gas transactions
Sales to IES ⁽²⁾	—		0.1
Purchases from IES ⁽²⁾	—		2.3
Interest expense ⁽³⁾
Integrys Energy Group	0.1		0.1
Transactions with equity method investees
Charges from ATC for network transmission services	25.3		24.7
Charges to ATC for services and construction	2.4		2.4
Purchases of energy from WRPC	1.0		1.0
Charges to WRPC for operations	0.3		0.4
Equity earnings from WPS Investments, LLC ⁽⁴⁾	2.3		2.5


⁽¹⁾	Integrys Energy Group sold UPPCO in August 2014.


⁽²⁾	Integrys Energy Group sold IES's retail energy business in November 2014.


⁽³⁾	WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.


⁽⁴⁾	WPS Investments, LLC is a consolidated subsidiary of Integrys Energy Group that is jointly owned by Integrys Energy Group and us. At March 31, 2015, we had a 10.94% interest in WPS Investments, LLC 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, LLC.

Note 17—New Accounting Pronouncements

Recently Issued Accounting Guidance Not Yet Effective

In April 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides guidance for determining whether a cloud computing arrangement includes a software license, which should be accounted for consistent with the acquisition of other software licenses. Cloud computing arrangements that do not include a software license should be accounted for as service contracts. This guidance may be applied either prospectively to new cloud computing arrangements, or retrospectively by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

In April 2015 the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs." The guidance requires debt issuance costs to be presented on the balance sheet as a reduction to the carrying value of the corresponding debt, rather than as an asset as it is currently presented. The standard requires retrospective application by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.

In February 2015 the FASB issued ASU 2015-02, "Amendments to the Consolidation Analysis." The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.

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In January 2015 the FASB issued ASU 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items." This guidance eliminates the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as extraordinary items in the future.

In May 2014 the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. 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 currently effective for us for the reporting period ending March 31, 2017; however, in April 2015 the FASB issued an exposure draft proposing to delay the effective date for one year. The standard requires either 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. We are 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, 2014.

SUMMARY

We are an 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 March 31				Change in 2015 Over 2014
(Millions)	2015		2014		Change in 2015 Over 2014
Electric utility operations	$	27.9	$	27.2	2.6	%
Natural gas utility operations	8.9		20.7		(57.0	)%
Other operations	2.2		2.4		(8.3	)%
Net income attributed to common shareholder	$	39.0	$	50.3	(22.5	)%

First Quarter 2015 Compared with First Quarter 2014

The $11.3 million decrease in our earnings was driven by:


•	An approximate $11 million after-tax decrease in margins related to our 2015 PSCW rate order, effective January 1, 2015. The decrease was driven by a natural gas rate decrease. See Note 14, Regulatory Environment, for more information.


•	An approximate $6 million after-tax decrease in margins due to sales volume variances, driven by warmer quarter-over-quarter weather. Although weather was colder than normal in the first quarter of 2015, it was warmer than the extreme cold of 2014.

These decreases were partially offset by a $7.7 million after-tax decrease in operating expenses. The decrease was driven by lower electric utility maintenance expense, primarily due to a planned major outage in 2014 at the Pulliam plant.

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Electric Utility Segment Operations



	Three Months Ended March 31						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014			Change in 2015 Over 2014
Revenues	$	295.8		$	321.4		(8.0	)%
Fuel and purchased power costs	115.2			130.6			(11.8	)%
Margins	180.6			190.8			(5.3	)%

Operating and maintenance expense	91.6			105.2			(12.9	)%
Depreciation and amortization expense	25.0			23.5			6.4	%
Taxes other than income taxes	10.9			11.3			(3.5	)%
Operating income	53.1			50.8			4.5	%

Miscellaneous income	2.8			3.5			(20.0	)%
Interest expense	10.9			10.9			—	%
Other expense	(8.1		)	(7.4		)	9.5	%

Income before taxes	$	45.0		$	43.4		3.7	%

Sales in kilowatt-hours
Residential	762.1			818.8			(6.9	)%
Commercial and industrial	1,969.1			1,956.6			0.6	%
Wholesale	635.5			666.1			(4.6	)%
Opportunity sales	302.0			113.6			165.8	%
Other	9.2			9.4			(2.1	)%
Total sales in kilowatt-hours	3,677.9			3,564.5			3.2	%

Weather
Actual heating degree days	3,946			4,515			(12.6	)%
Normal heating degree days	3,662			3,646			0.4	%

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.

First Quarter 2015 Compared with First Quarter 2014

Margins

Electric utility segment margins decreased $10.2 million, driven by:


•	An approximate $5 million decrease in margins related to sales volume variances. Margins from residential customers decreased, driven by the warmer weather in 2015.


•	An approximate $4 million decrease in margins related to our PSCW rate order, effective January 1, 2015. Although the PSCW approved an electric rate increase, the majority of the increase related to higher costs of fuel for electric generation, which has no impact on margins. See Note 14, Regulatory Environment, for more information.


◦	Margins decreased approximately $6 million as a result of the PSCW rate order and rate design.


◦	Margins were negatively impacted by approximately $1 million due to higher fuel costs not included in the fuel rule recovery mechanism. The majority of this was higher fly ash disposal costs in 2015.


◦	These decreases in margins were partially offset by an increase of approximately $3 million related to fuel and purchased power cost over-collections in 2015, compared with under-collections in 2014. 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 decrease in wholesale margins driven by lower sales volumes in 2015.

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Operating Income

Operating income at the electric utility segment increased $2.3 million. The increase was primarily driven by a $12.5 million decrease in operating expenses, partially offset by the $10.2 million decrease in margins discussed above.

The decrease in operating expenses was driven by:


•	A $7.9 million decrease in maintenance expense, primarily due to a planned major outage at the Pulliam plant in 2014, as well as lower maintenance at our jointly-owned plants in 2015.


•	A $2.5 million decrease in asset usage charges from IBS.


•	A $1.6 million net decrease in employee benefit costs, driven by amortization in 2014 of a prior year deferral of certain employee benefit costs.

These decreases were partially offset by a $1.5 million increase in depreciation and amortization expense, mainly due to the installation of scrubbers at the Columbia plant in April 2014.

Natural Gas Utility Segment Operations



	Three Months Ended March 31						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014			Change in 2015 Over 2014
Revenues	$	131.5		$	238.7		(44.9	)%
Natural gas purchased for resale	92.8			179.8			(48.4	)%
Margins	38.7			58.9			(34.3	)%

Operating and maintenance expense	15.9			16.9			(5.9	)%
Depreciation and amortization expense	4.2			4.0			5.0	%
Taxes other than income taxes	1.5			1.3			15.4	%
Operating income	17.1			36.7			(53.4	)%

Miscellaneous income	0.1			—			N/A
Interest expense	2.6			2.6			—	%
Other expense	(2.5		)	(2.6		)	(3.8	)%

Income before taxes	$	14.6		$	34.1		(57.2	)%

Retail throughput in therms
Residential	128.1			141.9			(9.7	)%
Commercial and industrial	74.2			87.2			(14.9	)%
Other	7.2			9.9			(27.3	)%
Total retail throughput in therms	209.5			239.0			(12.3	)%

Transport throughput in therms
Commercial and industrial	113.8			120.8			(5.8	)%

Total throughput in therms	323.3			359.8			(10.1	)%

Weather
Actual heating degree days	3,946			4,515			(12.6	)%
Normal heating degree days	3,662			3,646			0.4	%

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 41% decrease in the average per-unit cost of natural gas sold during the three months ended March 31, 2015, which had no impact on margins.

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First Quarter 2015 Compared with First Quarter 2014

Margins

Natural gas utility segment margins decreased $20.2 million, driven by:

•

An approximate $15 million decrease in margins due to a rate decrease effective January 1, 2015, including an approximate $5 million negative impact due to rate design changes. The 2015 rate order changed our rate design by increasing fixed charges but lowering volumetric charges to customers to better match the fixed costs of providing service. As a result, this rate design provides for lower cost recovery in periods of high sales volumes. Some of this impact is expected to reverse in future quarters with changes in sales volumes. See Note 14, Regulatory Environment, for more information.


•	An approximate $5 million decrease in margins due to warmer weather quarter over quarter.

Operating Income

Operating income at the natural gas utility segment decreased $19.6 million. This decrease was driven by the $20.2 million decrease in margins discussed above, partially offset by a $0.6 million decrease in operating expenses.

There were no individually significant items that impacted operating expenses.

Other Segment Operations



	Three Months Ended March 31					Change in 2015 Over 2014
(Millions)	2015			2014		Change in 2015 Over 2014
Operating (loss) income	$	(0.1	)	$	0.1	N/A
Other income	3.3			3.3		—	%
Income before taxes	$	3.2		$	3.4	(5.9	)%

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

Provision for Income Taxes

There was no material change in our effective tax rate quarter over quarter.

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 three months ended March 31, 2015, net cash provided by operating activities was $153.0 million, compared with $96.4 million during the same period in 2014. The $56.6 million increase in net cash provided by operating activities was driven by:


•	A $54.7 million increase in cash due to lower costs of natural gas, fuel, and purchased power in 2015, mainly driven by lower commodity prices and warmer weather in the first quarter of 2015.


•	A $45.7 million decrease in contributions to pension and other postretirement benefit plans.


•	An $18.8 million increase in cash related to decreased operating and maintenance costs in 2015. The decrease in operating and maintenance costs was partially driven by lower electric utility maintenance, primarily due to a planned major outage at the Pulliam plant in 2014.


•	A $16.4 million increase in cash from customer prepayments and credit balances. In 2015, customer prepayments grew during the warmer winter.

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•	A $3.5 million increase in cash received from income taxes, primarily driven by the net change in federal income tax refunds received quarter over quarter.

These increases in cash were partially offset by:


•	A $71.0 million decrease in cash collections from customers, mainly due to the impact of our 2015 rate order, lower commodity prices, and the warmer weather in the first quarter of 2015.


•	A $6.7 million increase in cash used for environmental remediation activities.


•	A $3.7 million increase in cash on deposit for operating and maintenance costs at Columbia and Edgewater.


•	A $1.1 million decrease in cash driven by higher collateral requirements in 2015 compared with 2014. Collateral requirements are based on forward natural gas and electricity prices and forward positions with counterparties.

Investing Cash Flows

During the three months ended March 31, 2015, net cash used for investing activities was $78.4 million, compared with $58.2 million during the same period in 2014. The $20.2 million increase in net cash used for investing activities was primarily due to an increase in net cash used to fund capital expenditures (discussed below).

Capital Expenditures

Capital expenditures by business segment for the three months ended March 31 were as follows:



Reportable Segment (millions)	2015		2014		Change in 2015 Over 2014
Electric utility	$	70.1	$	52.3	$	17.8
Natural gas utility	9.7		6.5		3.2
WPS consolidated	$	79.8	$	58.8	$	21.0

The increase in capital expenditures at the electric utility segment in 2015 compared with 2014 was primarily due to the ReACT^TM project at Weston 3 and the System Modernization and Reliability Project.

Financing Cash Flows

During the three months ended March 31, 2015, net cash used for financing activities was $76.1 million, compared with $36.5 million for the same period in 2014. The $39.6 million increase in net cash used for financing activities was driven by:


•	A $37.3 million increase in net repayments of commercial paper in 2015.


•	A $1.9 million increase in repayment of long-term debt to our parent in 2015 related to a lease arrangement for rail cars.

Significant Financing Activities

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

There were no significant changes in long-term debt during the first quarter of 2015.

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 independently of any other rating.

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Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of March 31, 2015, including those of our subsidiary:



			Payments Due By Period
(Millions)	Total Amounts Committed		2015		2016 to 2017		2018 to 2019		2020 and Later Years
Long-term debt principal and interest payments ⁽¹⁾	$	2,327.9	$	167.4	$	222.7	$	84.8	$	1,853.0
Operating lease obligations	15.6		0.3		1.6		1.0		12.7
Energy and transportation purchase obligations ⁽²⁾	1,191.0		167.7		250.6		225.7		547.0
Purchase orders ⁽³⁾	427.6		387.1		40.5		—		—
Pension and other postretirement funding obligations ⁽⁴⁾	7.1		2.2		4.9		—		—
Total contractual cash obligations	$	3,969.2	$	724.7	$	520.3	$	311.5	$	2,412.7


⁽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 $82.7 million at March 31, 2015, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 7, Commitments and Contingencies, for more information about environmental liabilities.

Capital Requirements

Projected capital expenditures by segment for 2015 through 2017, including amounts expended through March 31, 2015, are as follows:



(Millions)	2015			2016			2017		Total
Electric Utility
Distribution and energy supply operations projects	$	171		$	306		$	397	$	874
Environmental projects	171		*	42		*	23		236
Other projects	7			3			3		13

Natural Gas Utility
Distribution projects	36			33			32		101
Other projects	2			1			1		4
Total capital expenditures	$	387		$	385		$	456	$	1,228


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

All projected capital 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 2015 through 2017 primarily through internally generated funds (net of forecasted dividend payments), debt financings, and equity infusions from Integrys Energy Group. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.

We currently have a shelf registration statement under which we may issue up to $500.0 million of additional senior debt securities and/or first mortgage bonds. Amounts, prices, and terms will be determined at the time of future offerings.

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Under the merger agreement between our parent and Wisconsin Energy Corporation (Wisconsin Energy), we cannot issue long-term debt in excess of $300.0 million in 2015 without Wisconsin Energy's approval.

At March 31, 2015, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 5, Short-Term Debt and Lines of Credit, for more information on credit facilities and other short-term credit agreements.

Other Future Considerations

Coal Combustion Byproducts Rule

In April 2015, the EPA published in the Federal Register the final rule with new requirements for the management of coal combustion byproducts, primarily fly ash and bottom ash. These byproducts will be regulated as solid wastes rather than the more onerous hazardous waste standards. The rules are intended to address risks related to groundwater impacts, catastrophic failures, and air emissions. There will be additional requirements for recordkeeping, groundwater monitoring, and for structural integrity, including ongoing inspections and hazard assessments. There will also be more locational restrictions to protect wetlands and seismic impact zones. Although the rule will not affect our Pulliam plant, the rule will affect how we operate the Weston plant's bottom ash basins, beneficial reuse ash storage pads, and a landfill. We do not expect the compliance costs to be significant and expect to recover the costs in future rates.

Potential Addition of an Electric Generator at the Fox Energy Center Site

In 2013, we announced a need for an additional 400 to 500 megawatts of electric generating capacity by 2019 to meet the energy needs of our customers. After evaluating various options, we proposed building a new 400 megawatt natural gas-fired, combined-cycle generating unit for approximately $517 million to be located at our Fox Energy Center site. In January 2015, we filed an application with the PSCW for a Certificate of Public Convenience and Necessity. In April 2015, the PSCW verbally ordered us to withdraw our application for a Certificate of Public Convenience and Necessity following the closing of the acquisition of our parent by Wisconsin Energy Corporation (Wisconsin Energy) until a joint resource plan is submitted.

Presque Isle System Support Resource (SSR) Costs

In August 2013, Wisconsin Electric Power Company (Wisconsin Electric Power) notified MISO of 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 notified Wisconsin Electric Power in October 2013 that the Presque Isle facilities are required for reliability and would be SSR-designated. Under the terms of the SSR Tariff, 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. Several FERC dockets and rehearing requests regarding the amount and allocation of Presque Isle SSR costs are still pending.

On February 17, 2015, Wisconsin Electric Power notified MISO of its intent to rescind its decision to retire the Presque Isle Facility and requested termination of the SSR agreement, effective February 1, 2015. This intent to rescind was driven by a settlement agreement related to the proposed merger between Wisconsin Energy and our parent (described below under the heading “Michigan Electric Assets”). On February 18, 2015, MISO filed to terminate the SSR agreement effective February 1, 2015. The FERC approved MISO's request in April 2015.

SSR costs for our retail customers will be deferred until December 31, 2015, based on an April 2013 order from the PSCW. At that time, the PSCW will determine the appropriate ratemaking treatment. As of March 31, 2015, there were no material SSR costs for our retail customers deferred for future recovery under the currently approved allocation method. A potential reallocation of the Presque Isle SSR costs based on the pending FERC dockets and rehearing requests may result in an increase in SSR costs for us during the SSR-designated period, which ended February 1, 2015. SSR costs for Michigan customers are being recovered through the Power Supply Cost Recovery mechanism. SSR costs for our wholesale customers are being recovered through formula rates.

Michigan Electric Assets

In January 2015, our parent, Wisconsin Energy, the Attorney General of Michigan, the MPSC staff, and various other parties entered into a settlement agreement to resolve certain parties' objections to the proposed merger between Wisconsin Energy and our parent, including the sale of the Presque Isle facility currently owned by Wisconsin Energy, as well as our Michigan electric distribution assets and those of Wisconsin Energy, to UPPCO. In March 2015, an amended and restated settlement agreement was reached between our parent, Wisconsin Energy, the Attorney General of Michigan, the MPSC staff, and certain mines, which no longer required the sale of the Michigan electric distribution assets. The amended settlement agreement was approved, and in April 2015, the MPSC approved the proposed merger as well.

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

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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. The FERC ordered preliminary hearings to begin and expects to issue an initial decision by November 30, 2015.

In October 2014, the FERC 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.

In January 2015, and in response to a filing made by MISO transmission owners, the FERC approved a 50-basis point adder to the authorized ROE based on the transmission owners' participation as members in a regional transmission organization. The FERC ordered an effective date of January 6, 2015, subject to refund, and subject to the outcome of the November 2013 complaint proceeding discussed above. Collection of the ROE adder was also deferred pending the outcome of the November 2013 complaint proceeding.

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint.

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 ROE could result in lower equity earnings and dividends from ATC in the future. Although we are currently unable to determine how the FERC may rule in this complaint, we believe it is probable that a refund will be required upon resolution of this issue.

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 is not expected to impact us in 2015.

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 the middle of 2015. The proposed emission rate limits may not be achievable for coal-fired 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 and are currently being reviewed.

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 nationwide 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 in the summer of 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 this area are not expected to be significant at this time. Ongoing evaluations will be conducted as more information on the extent of such physical changes becomes available.

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

The Dodd-Frank Act was signed into law in July 2010. Some, but not all of the Commodity Futures Trading Commission (CFTC) rulemakings to implement the new law, 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. However, some of the key rules have not been finalized yet 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 evaluate in a comprehensive way how the CFTC's final Dodd-Frank Act rules will ultimately affect us. Certain provisions of the Dodd-Frank Act relating to derivatives and the CFTC's proposed rules could significantly increase our regulatory costs and/or collateral requirements or limit our ability to enter into or maintain certain derivative positions, which we use to hedge commercial risks. We continue to monitor developments related to the Dodd-Frank Act rulemakings and their potential impact on our future financial results. We have implemented or modified compliance policies and procedures to address the requirements of the Dodd-Frank Act rules that have taken effect to date.

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, 2014, 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 2014 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 March 31, 2015, 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 7, 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 2014 Annual Report on Form 10-K, which was filed with the SEC on March 2, 2015.

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 10, 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:	May 5, 2015	/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 MARCH 31, 2015



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 March 31, 2015, 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

Three Months Ended March 31

Effective tax rate