WISCONSIN PUBLIC SERVICE CORP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - WISCONSIN PUBLIC SERVICE CORP	a2015q2wps10-qexhibit322.htm
EX-31.1 - EXHIBIT 31.1 - WISCONSIN PUBLIC SERVICE CORP	a2015q2wps10-qexhibit311.htm
EX-31.2 - EXHIBIT 31.2 - WISCONSIN PUBLIC SERVICE CORP	a2015q2wps10-qexhibit312.htm
EX-32.1 - EXHIBIT 32.1 - WISCONSIN PUBLIC SERVICE CORP	a2015q2wps10-qexhibit321.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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

August 5, 2015

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WISCONSIN PUBLIC SERVICE CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 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	WEC Merger	6
	Note 3	Cash and Cash Equivalents	7
	Note 4	Goodwill and Other Intangible Assets	7
	Note 5	Short-Term Debt and Lines of Credit	7
	Note 6	Income Taxes	7
	Note 7	Commitments and Contingencies	8
	Note 8	Employee Benefit Plans	11
	Note 9	Stock-Based Compensation	11
	Note 10	Common Equity	12
	Note 11	Risk Management Activities	12
	Note 12	Fair Value	14
	Note 13	Miscellaneous Income	16
	Note 14	Regulatory Environment	16
	Note 15	Segments of Business	17
	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			20
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			29
ITEM 4.	Controls and Procedures			30
PART II.	OTHER INFORMATION			31
ITEM 1.	Legal Proceedings			31
ITEM 1A.	Risk Factors			31
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			31
ITEM 6.	Exhibits			31
Signature				32
EXHIBIT INDEX				33

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Acronyms Used in this Quarterly Report on Form 10-Q



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
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
WBS	WEC Business Services, LLC (formerly known as Integrys Business Support, LLC)
WDNR	Wisconsin Department of Natural Resources
WEC	WEC Energy Group, Inc.
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 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 terms and conditions of the FERC, MPSC, and PSCW orders approving the WEC Merger could reduce anticipated benefits, and the ability to successfully integrate our operations with Wisconsin Energy Corporation;


•	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 Holding 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						Six Months Ended
	June 30						June 30
(Millions)	2015			2014			2015			2014
Operating revenues	$	330.3		$	359.0		$	755.3		$	915.0

Cost of fuel, natural gas, and purchased power	120.4			147.7			321.0			450.8
Operating and maintenance expense	125.2			135.4			239.6			262.5
Depreciation and amortization expense	30.2			29.0			60.1			57.4
Property and revenue taxes	10.3			10.6			20.5			20.6
Operating income	44.2			36.3			114.1			123.7

Miscellaneous income	6.3			6.8			13.1			14.3
Interest expense	13.2			14.3			27.1			28.3
Other expense	(6.9		)	(7.5		)	(14.0		)	(14.0		)

Income before taxes	37.3			28.8			100.1			109.7
Provision for income taxes	13.9			10.9			36.9			40.7
Net income	23.4			17.9			63.2			69.0

Preferred stock dividend requirements	(0.8		)	(0.8		)	(1.6		)	(1.6		)
Net income attributed to common shareholder	$	22.6		$	17.1		$	61.6		$	67.4

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

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WISCONSIN PUBLIC SERVICE CORPORATION



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	June 30		December 31
(Millions, except share and per share data)	2015		2014
Assets
Cash and cash equivalents	$	3.7	$	5.4
Accounts receivable, net of reserves of $4.8 and $3.2, respectively	109.7		130.8
Accrued unbilled revenues	43.6		72.3
Receivables from related parties	4.9		1.3
Inventories
Fuel and gas	83.2		85.0
Materials and supplies, at average cost	47.4		39.2
Prepaid taxes	51.2		65.7
Other current assets	27.4		18.3
Current assets	371.1		418.0

Property, plant, and equipment, net of accumulated depreciation of $1,541.0 and $1,542.5, respectively	3,231.0		3,131.0
Regulatory assets	470.2		457.1
Goodwill	36.4		36.4
Pension and other postretirement benefit assets	140.5		128.9
Other long-term assets	105.7		107.3
Total assets	$	4,354.9	$	4,278.7

Liabilities and Shareholders’ Equity
Short-term debt	$	164.8	$	145.1
Current portion of long-term debt	125.0		125.0
Current portion of long-term debt to parent	3.2		2.5
Accounts payable	170.8		161.6
Payables to related parties	18.4		16.9
Other current liabilities	63.0		75.4
Current liabilities	545.2		526.5

Long-term debt to parent	—		2.9
Long-term debt	1,049.6		1,049.5
Deferred income taxes	754.6		722.1
Deferred investment tax credits	7.6		7.8
Regulatory liabilities	310.7		318.4
Environmental remediation liabilities	81.8		86.3
Pension and other postretirement benefit obligations	39.3		37.6
Payables to related parties	5.1		5.4
Other long-term liabilities	80.6		71.6
Long-term liabilities	2,329.3		2,301.6

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	808.4		782.0
Retained earnings	525.2		521.8
Total liabilities and shareholders’ equity	$	4,354.9	$	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)				June 30			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				808.4			782.0
Retained earnings				525.2			521.8
Total common stock equity				1,429.2			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	3.2			3.4
Total				3.2			5.4
Current portion of long-term debt to parent				(3.2		)	(2.5		)
Total long-term debt to parent				—			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				(0.5		)	(0.6		)
Total				1,174.6			1,174.5
Current portion of long-term debt				(125.0		)	(125.0		)
Total long-term debt				1,049.6			1,049.5
Total capitalization				$	2,530.0		$	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)	Six Months Ended
	June 30
(Millions)	2015			2014
Operating Activities
Net income	$	63.2		$	69.0
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	60.6			57.9
Deferred income taxes and investment tax credits, net	25.6			34.9
Pension and other postretirement contributions	(0.7		)	(46.5		)
Changes in working capital
Accounts receivable and accrued revenues	43.3			20.7
Inventories	(2.5		)	(10.1		)
Other current assets	2.8			27.3
Accounts payable	(5.3		)	8.5
Other current liabilities	11.5			(13.1		)
Other, net	(13.5		)	(21.7		)
Net cash provided by operating activities	185.0			126.9

Investing Activities
Capital expenditures	(167.4		)	(124.0		)
Cost of removal, net of salvage	(2.8		)	(1.3		)
Other, net	(1.3		)	(1.6		)
Net cash used for investing activities	(171.5		)	(126.9		)

Financing Activities
Preferred stock dividend requirements	(1.6		)	(1.6		)
Short-term debt, net	19.7			34.8
Payments of long-term debt to parent	(2.2		)	(0.4		)
Dividends to parent	(57.6		)	(55.9		)
Equity contribution from parent	30.0			40.0
Other	(3.5		)	(2.3		)
Net cash (used for) provided by financing activities	(15.2		)	14.6

Net change in cash and cash equivalents	(1.7		)	14.6
Cash and cash equivalents at beginning of period	5.4			5.7
Cash and cash equivalents at end of period	$	3.7		$	20.3

Cash paid for interest	$	29.0		$	27.8
Cash paid (received) for income taxes	$	1.6		$	(9.2	)

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)

June 30, 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. When we refer to the "WEC Merger," we are referring to the acquisition of our parent company, formerly known as Integrys Energy Group, by Wisconsin Energy Corporation, which was completed on June 29, 2015.

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.

Our balance sheet reflects the historical basis of our assets and liabilities as we did not elect pushdown accounting for the WEC Merger. This is consistent with how our financial statements are viewed by our regulators.

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

As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below.

Statements of Income:


•	Certain amortizations of deferrals were reclassified from operating and maintenance expense to cost of fuel, natural gas, and purchased power; depreciation and amortization expense; and miscellaneous income.


•	Payroll taxes of $2.0 million and $4.6 million for the three and six months ended June 30, 2014, respectively, were reclassified from taxes other than income taxes to operating and maintenance expense. The taxes other than income taxes line item was also renamed to property and revenue taxes.


•	Certain expenses in cost of fuel, natural gas, and purchased power were reclassified to operating revenues, operating and maintenance expense, and depreciation and amortization expense. The amounts reclassified to operating and maintenance expense were $3.4 million and $7.1 million for the three and six months ended June 30, 2014, respectively.

Balance Sheets:


•	Current regulatory assets of $1.4 million and $23.6 million were reclassified to accounts receivable and long-term regulatory assets, respectively.


•	Current regulatory liabilities of $6.1 million and $15.1 million were reclassified to other current liabilities and long-term regulatory liabilities, respectively.

Statements of Cash Flows:


•	Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections.

Note 2—WEC Merger

On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of WEC. The merger was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. We do not believe that the conditions set forth in the various regulatory orders approving the merger will have a material impact on our operations or financial results.

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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 $45.0 million and $46.3 million for the six months ended June 30, 2015 and 2014, respectively. 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 six months ended June 30, 2015, and 2014. In the second quarter of 2015, we completed our annual goodwill impairment test, and no impairment resulted from this test.

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



	June 30, 2015							December 31, 2014
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	15.6	$	(5.9	)	$	9.7	$	15.6	$	(4.3	)	$	11.3
Unamortized intangible assets	0.4		—			0.4		—		—			—
Total intangible assets	$	16.0	$	(5.9	)	$	10.1	$	15.6	$	(4.3	)	$	11.3


*	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 June 30, 2015, was approximately four years.

Note 5—Short-Term Debt and Lines of Credit

Our outstanding short-term borrowings were as follows:



(Millions, except percentages)	June 30, 2015				December 31, 2014
Commercial paper	$	164.8		*	$	145.1
Average interest rate on commercial paper outstanding	0.30		%		0.32		%


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

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2015, and 2014, was $110.4 million and $18.5 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	June 30, 2015		December 31, 2014
Revolving credit facility	06/13/2017	$	115.0	$	115.0
Revolving credit facility	05/08/2019	135.0		135.0
Total short-term credit capacity		$	250.0	$	250.0

Less:
Commercial paper outstanding		164.8		145.1
Available capacity under existing agreements		$	85.2	$	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:



	Three Months Ended June 30				Six months ended June 30
	2015		2014		2015		2014
Effective tax rate	37.3	%	37.8	%	36.9	%	37.1	%

Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for state income tax obligations. No other items had a significant impact on our effective tax rates during the three and six months ended June 30, 2015, and 2014.

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We had no liabilities for unrecognized tax benefits at June 30, 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.

The following table shows our minimum future commitments related to these purchase obligations as of June 30, 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	$	816.3	$	61.4	$	78.9	$	54.1	$	56.8	$	58.1	$	507.0
Coal supply and transportation	2019	154.0		35.6		39.0		34.9		33.4		11.1		—
Natural gas utility supply and transportation	2024	218.9		20.7		43.8		42.9		42.4		27.1		42.0
Total		$	1,189.2	$	117.7	$	161.7	$	131.9	$	132.6	$	96.3	$	549.0

(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. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. 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 these units starting June 1, 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 expected 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 June 30, 2015. It is unknown whether the Sierra Club will take further action in the future.

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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 Unit 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 Edgewater Unit 4 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.

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) 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 and included an issue related to reporting nitrogen oxide emissions from the Weston 4 auxiliary boiler. In June 2015, the WDNR issued an NOV to us alleging that we failed to comply with mercury 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. 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.

Air Quality

Mercury and Other Hazardous Air Pollutants:

In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, Wisconsin has mercury rules with the same compliance deadline that requires a 90% reduction of mercury. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect pending action by the D.C. Circuit Court of Appeals, which has the option to vacate the rule while the EPA completes its cost evaluation. If the rule is stayed or revoked, the Wisconsin Mercury Rule is likely to be the governing standard for our units. At this time, it is too early to determine what effect, if any, this ruling will have on our compliance plans.

We initiated certain capital projects for our wholly owned plants to achieve the required reductions for MATS or the Wisconsin Mercury Rule. These capital costs are expected to be recovered in future rates.

Sulfur Dioxide:

The EPA issued a 1-Hour Sulfur Dioxide (SO₂) National Ambient Air Quality Standard (NAAQS) that became effective in August 2010. In May 2014, the EPA issued the proposed Data Requirements Rule that would establish procedures and timelines for implementation of the standard. The proposed rule describes the EPA's plans for allowing the states to use either monitoring or modeling to make designations.

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As proposed, the rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as nonattainment, then they would have to make emission reductions by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including permitting constraints for area sources and for other new or existing sources in the area.

In March 2015, a Federal Court in the Northern District of California entered a consent decree relating to the implementation of the revised 1-Hour SO₂ standard that Sierra Club and EPA had agreed upon in May 2014. This consent decree has 1-Hour SO₂ implementation dates that are sooner than the proposed Data Requirements Rule. The EPA has not yet indicated how, in light of this consent decree, the Data Requirements Rule will be finalized.

We believe our fleet, with the exception of the Pulliam plant, is well positioned to meet this regulation once it is finalized. The Pulliam plant is located in Brown County, which has been preliminarily determined to be in nonattainment with the standard based on monitoring data from 2012 through 2014. The WDNR has indicated that additional modeling and monitoring data will be required prior to final attainment designations being made in 2017 and 2020. We are currently working closely with the state of Wisconsin as they determine the attainment status of the areas and the effect, if any, on the Pulliam plant.

Land Quality

Coal Combustion Residuals (CCR) Rule:

In April 2015, the EPA published the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule in the Federal Register. The final rule regulates the disposal of coal combustion byproducts, primarily fly ash and bottom ash, as a nonhazardous waste. 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 structural integrity, including ongoing inspections and hazard assessments. There will also be more locational restrictions to protect wetlands and seismic impact zones. The rule will affect how we operate the Weston plant's bottom ash basins and an offsite landfill. However, we have landfill capacity that meets the rule requirements, if needed, for our coal combustion product sources. We do not expect the compliance costs to be significant because we currently have a program of beneficial utilization for most of our coal combustion byproducts and expect to recover the costs in future rates.

Water Quality

Clean Water Act Rule:

In August 2014, the EPA issued a final Clean Water Act rule under Section 316(b), which requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to the the Weston and Pulliam plants.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. BTA determinations must also be made to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. The rule requires state permitting agencies, including the WDNR, to make BTA determinations for IM and EM over the next several years, subject to EPA oversight, when facility permits are reissued. Based on our assessment, we believe that existing technologies at Weston Units 3 and 4 satisfy the IM and EM requirements by virtue of their existing cooling towers. In addition, it is expected that the WDNR will determine that no modifications will be required at Weston Unit 2 due to low projected utilization. However, Pulliam Units 7 and 8 do not have the technologies to satisfy the IM and EM BTA requirements.

During 2015-18, we plan to complete studies to address the EM BTA requirements and evaluate the available IM options for Pulliam Units 7 and 8. We also expect limited studies to support WDNR BTA determinations to be conducted at the Weston facility. We cannot yet determine what, if any, intake structure or operational modifications will be required to meet the EM BTA requirements for Pulliam Units 7 and 8. We expect to recover any future compliance costs in future rates.

Manufactured Gas Plant Remediation

We have identified several sites at which we, or a predecessor company, owned or operated a manufactured gas plant. These sites are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Sites Program.

The future costs for detailed site investigation and future remediation are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

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We established the following reserves and regulatory assets related to manufactured gas plant sites:



(Millions)	June 30, 2015		December 31, 2014
Regulatory assets	$	100.4	$	102.3
Reserves for future remediation	81.8		86.3

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 June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
(Millions)	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	2.7		$	1.9		$	5.4		$	4.3		$	2.1		$	1.4		$	4.3		$	3.9
Interest cost	7.8			8.5			15.8			17.2			2.6			2.2			5.2			6.1
Expected return on plan assets	(16.0		)	(15.8		)	(32.4		)	(32.0		)	(4.0		)	(3.4		)	(8.0		)	(8.0		)
Loss on plan settlement	—			0.4			0.1			0.4			—			—			—			—
Amortization of prior service cost (credit)	0.1			0.2			0.1			0.3			(2.3		)	(2.3		)	(4.6		)	(3.4		)
Amortization of net actuarial loss	5.6			3.8			10.5			7.5			0.9			0.7			1.9			1.3
Net periodic benefit cost (credit)	$	0.2		$	(1.0	)	$	(0.5	)	$	(2.3	)	$	(0.7	)	$	(1.4	)	$	(1.2	)	$	(0.1	)

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.

Note 9—Stock-Based Compensation

Our employees were granted awards under Integrys Holding’s stock-based compensation plans. Per the WEC Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were canceled in exchange for the right to be paid out in cash to award recipients. See Note 2, WEC Merger, for more information regarding the merger.

The intrinsic values of the awards canceled due to the merger were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options canceled was not significant.

Compensation cost associated with stock-based compensation awards was allocated to us based on the percentages used for allocation of the award recipients’ labor costs. The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the three and six months ended June 30:



	Three Months Ended June 30				Six Months Ended June 30
(Millions)	2015		2014		2015		2014
Stock options	$	—	$	0.2	$	—	$	0.3
Performance stock rights	1.1		3.6		1.3		3.8
Restricted share units	2.1		1.0		3.5		2.0
Total stock-based compensation expense	$	3.2	$	4.8	$	4.8	$	6.1
Deferred income tax benefit	$	1.3	$	1.9	$	1.9	$	2.4

A summary of the activity for our stock-based compensation awards for the six months ended June 30, 2015, is presented below:



	Stock Options		Performance Stock Rights		Restricted Stock Units
Outstanding at December 31, 2014	5,714		13,937		70,544
Granted	—		—		30,174
Dividend equivalents	N/A		N/A		1,267
Exercised/Distributed/Vested and Released *	(2,752	)	(2,229	)	(28,428	)
Adjustment for performance stock rights distributed or canceled	N/A		9,555		N/A
Transferred	—		—		(166	)
Canceled due to WEC Merger	(2,962	)	(21,263	)	(73,391	)
Outstanding at June 30, 2015	—		—		—

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*	The intrinsic value of restricted share unit awards vested and released was $2.2 million. The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant.

Note 10—Common Equity

Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends or return capital to the sole holder of our common stock, Integrys Holding.

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 Holding 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 Holding'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%.

As of June 30, 2015, our total restricted retained earnings were $525.2 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $32.7 million at June 30, 2015.

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

Integrys Holding 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 Holding or its other subsidiaries.

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. We use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs and to reduce price risk related to coal transportation costs. Financial transmission rights (FTRs) are used to manage electric transmission congestion costs in the MISO market.

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



		June 30, 2015
(Millions)	Balance Sheet Presentation *	Assets		Liabilities
Natural gas contracts	Other current	$	0.6	$	0.8
Natural gas contracts	Other long-term	—		0.1
FTRs	Other current	4.1		—
Petroleum product contracts	Other current	—		0.3
Coal contracts	Other current	—		4.1
Coal contracts	Other long-term	—		2.1
	Other current	4.7		5.2
	Other long-term	—		2.2
Total		$	4.7	$	7.4


*	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.

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



	June 30, 2015
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	4.7	$	0.6	$	4.1
Derivative assets not subject to master netting or similar arrangements	—				—
Total risk management assets	$	4.7			$	4.1

Derivative liabilities subject to master netting or similar arrangements	$	1.2	$	1.2	$	—
Derivative liabilities not subject to master netting or similar arrangements	6.2				6.2
Total risk management liabilities	$	7.4			$	6.2



	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)	June 30, 2015		December 31, 2014
Cash collateral provided to others related to contracts under master netting or similar arrangements *	$	16.9	$	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 June 30						Six Months Ended June 30
(Millions)	Financial Statement Presentation	2015			2014			2015			2014
Natural gas	Balance Sheet — Regulatory assets	$	0.7		$	(0.3	)	$	1.6		$	(0.1	)
Natural gas	Balance Sheet — Regulatory liabilities	0.1			(0.2		)	—			(0.1		)
FTRs	Balance Sheet — Regulatory assets	(7.2		)	(1.0		)	(7.0		)	(0.9		)
FTRs	Balance Sheet — Regulatory liabilities	2.4			1.1			2.0			1.0
Petroleum	Balance Sheet — Regulatory assets	0.5			—			0.9			—
Coal	Balance Sheet — Regulatory assets	0.6			(0.1		)	(4.0		)	0.5
Coal	Balance Sheet — Regulatory liabilities	—			0.9			—			2.5

We had the following notional volumes of outstanding derivative contracts:

(Millions)

June 30, 2015

December 31, 2014

Commodity

Purchases

Other Transactions

Purchases

Other Transactions

Natural gas (therms)

122.9

N/A

1,025.4

N/A

FTRs (kilowatt-hours)

N/A

8,577.9

N/A

4,287.7

Petroleum products (barrels)

0.1

N/A

—

N/A

Coal contract (tons)

2.2

N/A

3.0

N/A

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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.

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.

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. 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:



	June 30, 2015
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.6	$	—	$	—	$	0.6
Financial transmission rights (FTRs)	—		—		4.1		4.1
Total	$	0.6	$	—	$	4.1	$	4.7

Risk management liabilities
Natural gas contracts	$	0.9	$	—	$	—	$	0.9
Petroleum product contracts	0.3		—		—		0.3
Coal contracts	—		0.8		5.4		6.2
Total	$	1.2	$	0.8	$	5.4	$	7.4

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	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 or six months ended June 30, 2015, and 2014.

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 June 30, 2015:

Fair Value (Millions)

Assets

Liabilities

Valuation Technique

Unobservable Input

Average or Range

FTRs

4.1

—

Market-based

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

$172.71

Coal contracts

—

5.4

Market-based

Forward market prices ($/ton) ⁽²⁾

$9.86 – $13.23


⁽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 June 30, 2015									Six Months Ended June 30, 2015
(Millions)	FTRs			Coal Contracts			Total			FTRs			Coal Contracts			Total
Balance at the beginning of period	$	0.6		$	(6.2	)	$	(5.6	)	$	1.9		$	(2.2	)	$	(0.3	)
Net realized losses included in earnings	(1.2		)	—			(1.2		)	(2.4		)	—			(2.4		)
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(4.8		)	0.3			(4.5		)	(5.0		)	(4.0		)	(9.0		)
Purchases	9.8			—			9.8			9.8			—			9.8
Settlements	(0.3		)	0.5			0.2			(0.2		)	0.8			0.6
Balance at the end of period	$	4.1		$	(5.4	)	$	(1.3	)	$	4.1		$	(5.4	)	$	(1.3	)

	Three Months Ended June 30, 2014									Six Months Ended June 30, 2014
(Millions)	FTRs			Coal Contracts			Total			FTRs			Coal Contracts			Total
Balance at the beginning of period	$	0.5		$	0.3		$	0.8		$	1.2		$	(2.5	)	$	(1.3	)
Net realized gains included in earnings	0.1			—			0.1			0.8			—			0.8
Net unrealized gains recorded as regulatory assets or liabilities	0.1			0.8			0.9			0.1			3.0			3.1
Purchases	4.4			—			4.4			4.3			—			4.3
Settlements	(1.1		)	(0.2		)	(1.3		)	(2.4		)	0.4			(2.0		)
Balance at the end of period	$	4.0		$	0.9		$	4.9		$	4.0		$	0.9		$	4.9

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.

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Fair Value of Financial Instruments

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



	June 30, 2015				December 31, 2014
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	1,174.6	$	1,208.6	$	1,174.5	$	1,286.2
Long-term debt to parent	3.2		3.3		5.4		5.7
Preferred stock	51.2		53.2		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.

Note 13—Miscellaneous Income

Total miscellaneous income was as follows:



	Three Months Ended June 30				Six Months Ended June 30
(Millions)	2015		2014		2015		2014
Equity portion of allowance for funds used during construction	$	3.4	$	2.7	$	6.3	$	6.3
Earnings from equity method investment in ATC	2.0		2.5		4.3		5.1
Key executive life insurance for retired employees	—		0.7		0.9		1.4
Other	0.9		0.9		1.6		1.5
Total miscellaneous income	$	6.3	$	6.8	$	13.1	$	14.3

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 higher operating and maintenance costs, general inflation, and an increase in the amount of outstanding equity supporting construction projects.

In May 2015, we filed a revised application with the PSCW adjusting our requested retail electric rate increase to $96.9 million and our requested retail natural gas rate increase to $9.1 million. The revised requests are primarily driven by revisions to retail electric and natural gas revenues and employee benefit costs.

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 $42.0 million. In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we are refunding approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 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

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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 $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we are refunding approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 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 rate 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 $8.0 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.

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 June 30, 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.

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The tables below present information related to our reportable segments:



	Regulated
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other			Reconciling Eliminations			WPS Consolidated
Three Months Ended June 30, 2015
External revenues	$	277.5		$	52.8		$	330.3		$	—		$	—		$	330.3
Intersegment revenues	—			2.1			2.1			0.2			(2.3		)	—
Depreciation and amortization expense	25.8			4.2			30.0			0.1			0.1			30.2
Miscellaneous income	3.6			0.1			3.7			2.6			—			6.3
Interest expense	10.9			2.6			13.5			(0.3		)	—			13.2
Provision for income taxes	12.9			0.1			13.0			0.9			—			13.9
Preferred stock dividend requirements	(0.6		)	(0.2		)	(0.8		)	—			—			(0.8		)
Net income (loss) attributed to common shareholder	20.7			(0.1		)	20.6			2.0			—			22.6

	Regulated
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other			Reconciling Eliminations			WPS Consolidated
Three Months Ended June 30, 2014
External revenues	$	291.6		$	67.4		$	359.0		$	—		$	—		$	359.0
Intersegment revenues	—			2.7			2.7			0.4			(3.1		)	—
Depreciation and amortization expense	24.9			4.1			29.0			0.2			(0.2		)	29.0
Miscellaneous income	2.9			0.2			3.1			3.7			—			6.8
Interest expense	11.2			2.6			13.8			0.5			—			14.3
Provision for income taxes	9.7			0.2			9.9			1.0			—			10.9
Preferred stock dividend requirements	(0.6		)	(0.2		)	(0.8		)	—			—			(0.8		)
Net income (loss) attributed to common shareholder	14.9			(0.1		)	14.8			2.3			—			17.1

	Regulated
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other			Reconciling Eliminations			WPS Consolidated
Six Months Ended June 30, 2015
External revenues	$	573.6		$	181.7		$	755.3		$	—		$	—		$	755.3
Intersegment revenues	—			4.7			4.7			0.4			(5.1		)	—
Depreciation and amortization expense	51.5			8.4			59.9			0.2			—			60.1
Miscellaneous income	6.6			0.2			6.8			6.3			—			13.1
Interest expense	21.8			5.2			27.0			0.1			—			27.1
Provision for income taxes	29.3			5.7			35.0			1.9			—			36.9
Preferred stock dividend requirements	(1.3		)	(0.3		)	(1.6		)	—			—			(1.6		)
Net income attributed to common shareholder	48.6			8.8			57.4			4.2			—			61.6

	Regulated
(Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other			Reconciling Eliminations			WPS Consolidated
Six Months Ended June 30, 2014
External revenues	$	613.3		$	301.7		$	915.0		$	—		$	—		$	915.0
Intersegment revenues	—			7.1			7.1			0.7			(7.8		)	—
Depreciation and amortization expense	49.2			8.1			57.3			0.4			(0.3		)	57.4
Miscellaneous income	6.6			0.2			6.8			7.5			—			14.3
Interest expense	22.1			5.2			27.3			1.0			—			28.3
Provision for income taxes	25.2			13.5			38.7			2.0			—			40.7
Preferred stock dividend requirements	(1.3		)	(0.3		)	(1.6		)	—			—			(1.6		)
Net income attributed to common shareholder	42.1			20.6			62.7			4.7			—			67.4

Note 16—Related Party Transactions

We and our subsidiary, WPS Leasing, routinely enter into transactions with related parties, including Integrys Holding, 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.

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

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



(Millions)	June 30, 2015		December 31, 2014
Notes payable *
Integrys Holding	$	3.2	$	5.4
Accounts Payable
Network transmission services from ATC	8.4		8.2
Liability related to income tax allocation
Integrys Holding	5.7		6.1


*	WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Holding. At June 30, 2015, and December 31, 2014, the current portion of the note payable was $3.2 million and $2.5 million, respectively.

The following table shows activity associated with related party transactions:



	Three Months Ended June 30				Six Months Ended June 30
(Millions)	2015		2014		2015		2014
Electric transactions
Sales to UPPCO ⁽¹⁾	$	—	$	5.8	$	—	$	11.2
Natural gas transactions
Sales to IES ⁽²⁾	—		0.1		—		0.2
Purchases from IES ⁽²⁾	—		0.1		—		2.4
Interest expense ⁽³⁾
Integrys Holding	0.1		0.1		0.2		0.2
Transactions with equity method investees
Charges from ATC for network transmission services	25.4		24.8		50.7		49.5
Charges to ATC for services and construction	2.2		2.7		4.6		5.1
Purchases of energy from WRPC	1.1		1.1		2.1		2.1
Charges to WRPC for operations	0.2		0.3		0.5		0.7
Equity earnings from WPS Investments, LLC ⁽⁴⁾	2.0		2.6		4.3		5.1
Sales of electricity to AMP Trillium, LLC	0.1		—		0.1		—


⁽¹⁾	Integrys Holding sold UPPCO in August 2014.


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


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


⁽⁴⁾	WPS Investments, LLC is a consolidated subsidiary of Integrys Holding that is jointly owned by Integrys Holding and us. At June 30, 2015, we had a 10.90% 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 Holding to WPS Investments, LLC.

Note 17—New Accounting Pronouncements

Recently Issued Accounting Guidance Not Yet Effective

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 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 was originally effective for us for the reporting period ending March 31, 2017; however, in July 2015 the FASB decided to delay the effective date for one year. Companies can still elect to adopt the standard as of the original effective date. 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

On June 29, 2015, the WEC Merger was completed, and our parent became a wholly owned subsidiary of WEC. We are an electric and natural gas utility and a wholly owned subsidiary of Integrys Holding, 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 June 30						Change in 2015 Over 2014		Six Months Ended June 30				Change in 2015 Over 2014
(Millions)	2015			2014			Change in 2015 Over 2014		2015		2014		Change in 2015 Over 2014
Electric utility operations	$	20.7		$	14.9		38.9	%	$	48.6	$	42.1	15.4	%
Natural gas utility operations	(0.1		)	(0.1		)	—	%	8.8		20.6		(57.3	)%
Other operations	2.0			2.3			(13.0	)%	4.2		4.7		(10.6	)%
Net income attributed to common shareholder	$	22.6		$	17.1		32.2	%	$	61.6	$	67.4	(8.6	)%

Second Quarter 2015 Compared with Second Quarter 2014

The $5.5 million increase in our earnings was driven by:


•	A $5.6 million after-tax decrease in operating expenses, driven by lower electric utility maintenance expense.


•	An approximate $3.0 million after-tax increase in margins related to our 2015 PSCW rate order, effective January 1, 2015. See Note 14, Regulatory Environment, for more information.

These increases were partially offset by an approximate $4.0 million after-tax decrease in margins due to sales volume variances, driven by lower use per residential customer and warmer weather in 2015.

Six Months 2015 Compared with Six Months 2014

The $5.8 million decrease in our earnings was driven by:


•	An approximate $10.0 million after-tax decrease in margins due to sales volume variances, driven by warmer weather in 2015.


•	An approximate $8.0 million after-tax decrease in margins related to our 2015 PSCW rate order, effective January 1, 2015. See Note 14, Regulatory Environment, for more information.

These decreases were partially offset by a $12.2 million after-tax decrease in operating expenses, driven by lower electric utility maintenance expense.

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Electric Utility Segment Operations



	Three Months Ended June 30						Change in 2015 Over 2014		Six Months Ended June 30						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014			Change in 2015 Over 2014		2015			2014			Change in 2015 Over 2014
Revenues	$	277.5		$	291.6		(4.8	)%	$	573.6		$	613.3		(6.5	)%
Fuel and purchased power costs	95.8			106.7			(10.2	)%	206.4			234.6			(12.0	)%
Margins	181.7			184.9			(1.7	)%	367.2			378.7			(3.0	)%

Operating and maintenance expense	105.3			116.9			(9.9	)%	203.2			226.6			(10.3	)%
Depreciation and amortization expense	25.8			24.9			3.6	%	51.5			49.2			4.7	%
Property and revenue taxes	9.1			9.6			(5.2	)%	18.1			18.8			(3.7	)%
Operating income	41.5			33.5			23.9	%	94.4			84.1			12.2	%

Miscellaneous income	3.6			2.9			24.1	%	6.6			6.6			—	%
Interest expense	10.9			11.2			(2.7	)%	21.8			22.1			(1.4	)%
Other expense	(7.3		)	(8.3		)	(12.0	)%	(15.2		)	(15.5		)	(1.9	)%

Income before taxes	$	34.2		$	25.2		35.7	%	$	79.2		$	68.6		15.5	%

Sales in kilowatt-hours
Residential	588.5			627.5			(6.2	)%	1,350.6			1,446.3			(6.6	)%
Commercial and industrial	1,977.9			1,969.6			0.4	%	3,947.0			3,926.2			0.5	%
Wholesale	629.1			665.3			(5.4	)%	1,264.6			1,331.5			(5.0	)%
Opportunity sales	124.1			156.0			(20.4	)%	426.1			269.5			58.1	%
Other	6.3			6.4			(1.6	)%	15.5			15.8			(1.9	)%
Total sales in kilowatt-hours	3,325.9			3,424.8			(2.9	)%	7,003.8			6,989.3			0.2	%

Weather *
Actual heating degree days	840			1,020			(17.6	)%	4,786			5,535			(13.5	)%
Normal heating degree days	981			975			0.6	%	4,643			4,621			0.5	%
Actual cooling degree days	98			109			(10.1	)%	98			109			(10.1	)%
Normal cooling degree days	137			141			(2.8	)%	137			141			(2.8	)%


*	Normal heating and cooling degree days are based on a 20-year average of monthly temperatures from the Green Bay Weather Station.

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.

Second Quarter 2015 Compared with Second Quarter 2014

Margins

Electric utility segment margins decreased $3.2 million, driven by:


•	An approximate $5.0 million decrease in margins related to sales volume variances. Margins from residential customers decreased, driven by lower use per customer and warmer weather in the second quarter of 2015.


•	A partially offsetting approximate $2.0 million increase in margins related to rates, driven by:


◦	An increase of approximately $3.0 million related to fuel and purchased power cost over-collections as compared with approved rates in 2015, as opposed to under-collections as compared with approved rates 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.


◦	This increase was partially offset by a decrease in margins of approximately $1.0 million as a result of the PSCW rate order and rate design, 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.

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Operating Income

Operating income at the electric utility segment increased $8.0 million. The increase was primarily driven by a $11.2 million decrease in operating expenses, partially offset by the $3.2 million decrease in margins discussed above.

The decrease in operating expenses was driven by:


•	A $13.2 million decrease in maintenance expense, primarily at the Fox Energy Center, Pulliam, and our jointly-owned plants in 2015. Maintenance costs were also lower in the second quarter of 2015 due to a planned major outage at the Weston plant in 2014.


•	A $1.2 million decrease in fly ash disposal costs in 2015.

These decreases were partially offset by:


•	A $1.8 million increase in electric transmission expenses.


•	A $0.9 million increase in depreciation and amortization expense, mainly due to the installation of scrubbers at the Columbia plant in April 2014.

Six Months 2015 Compared with Six Months 2014

Margins

Electric utility segment margins decreased 11.5 million, driven by:


•	An approximate $10.0 million decrease in margins related to sales volume variances. Margins from residential customers decreased, driven by warmer weather and lower use per customer in 2015.


•	An approximate $1.0 million decrease in margins related to rates.


◦	Margins decreased approximately $7.0 million as a result of the PSCW rate order and rate design, 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.

◦

These decreases in margins were partially offset by an increase of approximately $6.0 million related to fuel and purchased power cost over-collections as compared with approved rates in 2015, as opposed to under-collections as compared with approved rates 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 $1.0 million decrease in wholesale margins driven by a reduction in sales volumes. Certain wholesale customers have provisions in their contracts which allow them to reduce the amount of energy we provide to them.

Operating Income

Operating income at the electric utility segment increased $10.3 million. The increase was primarily driven by a $21.8 million decrease in operating expenses, partially offset by the $11.5 million decrease in margins discussed above.

The decrease in operating expenses was driven by:


•	A $21.1 million decrease in maintenance expense, primarily due to planned major outages at the Pulliam 8 plant and Weston 4 plant in 2014, as well as lower maintenance at the Fox Energy Center and our jointly-owned plants in 2015.


•	A $2.8 million decrease in asset usage charges from WBS.

These decreases were partially offset by:


•	A $3.6 million increase in electric transmission expenses.


•	A $2.3 million increase in depreciation and amortization expense, mainly due to the installation of scrubbers at the Columbia plant in April 2014.

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Natural Gas Utility Segment Operations



	Three Months Ended June 30						Change in 2015 Over 2014		Six Months Ended June 30						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014			Change in 2015 Over 2014		2015			2014			Change in 2015 Over 2014
Revenues	$	54.9		$	70.1		(21.7	)%	$	186.4		$	308.8		(39.6	)%
Natural gas purchased for resale	26.9			43.9			(38.7	)%	119.7			223.7			(46.5	)%
Margins	28.0			26.2			6.9	%	66.7			85.1			(21.6	)%

Operating and maintenance expense	20.0			18.4			8.7	%	36.3			35.8			1.4	%
Depreciation and amortization expense	4.2			4.1			2.4	%	8.4			8.1			3.7	%
Property and revenue taxes	1.1			1.0			10.0	%	2.2			1.8			22.2	%
Operating income	2.7			2.7			—	%	19.8			39.4			(49.7	)%

Miscellaneous income	0.1			0.2			(50.0	)%	0.2			0.2			—	%
Interest expense	2.6			2.6			—	%	5.2			5.2			—	%
Other expense	(2.5		)	(2.4		)	4.2	%	(5.0		)	(5.0		)	—	%

Income before taxes	$	0.2		$	0.3		(33.3	)%	$	14.8		$	34.4		(57.0	)%

Retail throughput in therms
Residential	33.1			39.9			(17.0	)%	161.2			181.8			(11.3	)%
Commercial and industrial	20.5			24.9			(17.7	)%	94.7			112.1			(15.5	)%
Other	8.2			4.7			74.5	%	15.4			14.6			5.5	%
Total retail throughput in therms	61.8			69.5			(11.1	)%	271.3			308.5			(12.1	)%

Transport throughput in therms
Commercial and industrial	78.9			79.8			(1.1	)%	192.7			200.6			(3.9	)%

Total throughput in therms	140.7			149.3			(5.8	)%	464.0			509.1			(8.9	)%

Weather *
Actual heating degree days	840			1,020			(17.6	)%	4,786			5,535			(13.5	)%
Normal heating degree days	981			975			0.6	%	4,643			4,621			0.5	%


*	Normal heating degree days are based on a 20-year average of monthly temperatures from the Green Bay Weather Station.

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 31% and 39% decrease in the average per-unit cost of natural gas sold during the three and six months ended June 30, 2015, which had no impact on margins.

Second Quarter 2015 Compared with Second Quarter 2014

Margins

Natural gas utility segment margins increased $1.8 million, driven by:

•

An approximate $4.0 million increase in margins related to the PSCW rate order, effective January 1, 2015. Although the PSCW approved a natural gas rate decrease, the increase in margins in the second quarter of 2015 was driven by rate design changes. The approved rate design increased fixed charges but lowered volumetric charges to customers to better match the fixed costs of providing service. As a result, this rate design provides for higher cost recovery in periods of low 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.


•	A partially offsetting $2.0 million decrease in margins related to sales volume variances. Margins from residential customers decreased, driven by warmer weather and lower use per customer in the second quarter of 2015.

Operating Income

Operating income at the natural gas utility segment remained the same quarter over quarter. The increase in margins of $1.8 million discussed above was offset by a $1.8 million increase in operating expenses. There were no individually significant items that impacted operating expenses.

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Six Months 2015 Compared with Six Months 2014

Margins

Natural gas utility segment margins decreased $18.4 million, driven by:

•

An approximate $12.0 million decrease in margins due to the PSCW rate order, effective January 1, 2015, including an approximate $3.0 million negative impact due to rate design changes. The approved rate design increased fixed charges but lowered 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 $7.0 million decrease in margins related to sales volume variances, driven by warmer weather in 2015.

Operating Income

Operating income at the natural gas utility segment decreased $19.6 million. This decrease was driven by the $18.4 million decrease in margins discussed above, as well as a $1.2 million increase in operating expenses. There were no individually significant items that impacted operating expenses.

Other Segment Operations



	Three Months Ended June 30				Change in 2015 Over 2014		Six Months Ended June 30					Change in 2015 Over 2014
(Millions)	2015		2014		Change in 2015 Over 2014		2015			2014		Change in 2015 Over 2014
Operating income (loss)	$	—	$	0.1	(100.0	)%	$	(0.1	)	$	0.2	N/A
Other income	2.9		3.2		(9.4	)%	6.2			6.5		(4.6	)%
Income before taxes	$	2.9	$	3.3	(12.1	)%	$	6.1		$	6.7	(9.0	)%

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

Provision for Income Taxes



	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014
Effective tax rate	37.3	%	37.8	%	36.9	%	37.1	%

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

LIQUIDITY AND CAPITAL RESOURCES

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

Operating Cash Flows

During the six months ended June 30, 2015, net cash provided by operating activities was $185.0 million, compared with $126.9 million during the same period in 2014. The $58.1 million increase in net cash provided by operating activities was driven by:


•	A $45.8 million decrease in contributions to pension and other postretirement benefit plans in 2015.


•	A $38.2 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.


•	A $25.7 million increase in cash from customer prepayments and credit balances. In 2015, customer prepayments grew during the warmer winter.

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These increases in cash were partially offset by:


•	A $22.6 million net decrease in cash related to lower collections from customers, partially offset by an increase in cash resulting from lower payments for natural gas, fuel, and purchased power in 2015. This net decrease was mainly due to the impact of our 2015 rate order, lower commodity prices, and the warmer weather in 2015.


•	A $10.8 million decrease in cash received from income taxes, primarily driven by the net period-over-period change in estimated tax payments.


•	A $10.0 million decrease in cash driven by higher collateral requirements in 2015. Additional collateral was required by MISO as a result of increased credit exposure of the combined companies that resulted from the WEC Merger.


•	A $6.9 million decrease in cash due to higher environmental remediation activities in 2015.


•	A $1.2 million increase in cash paid for interest in 2015.

Investing Cash Flows

During the six months ended June 30, 2015, net cash used for investing activities was $171.5 million, compared with $126.9 million during the same period in 2014. The $44.6 million increase in net cash used for investing activities was primarily due to an increase in cash used to fund capital expenditures (discussed below).

Capital Expenditures

Capital expenditures by business segment for the six months ended June 30 were as follows:



Reportable Segment (millions)	2015		2014		Change in 2015 Over 2014
Electric utility	$	145.6	$	106.1	$	39.5
Natural gas utility	21.8		17.9		3.9
WPS consolidated	$	167.4	$	124.0	$	43.4

The increase in capital expenditures at the electric utility segment in 2015 was primarily due to the ReACT^TM project at Weston 3 and the System Modernization and Reliability Project, partially offset by lower period-over-period capital expenditures related to environmental compliance projects at the Columbia plant.

Financing Cash Flows

During the six months ended June 30, 2015, net cash used for financing activities was $15.2 million, compared with net cash provided by financing activities of $14.6 million for the same period in 2014. The $29.8 million period-over-period change was driven by:


•	A $15.1 million decrease in net borrowings of commercial paper in 2015.


•	A $10.0 million decrease in equity contributions from our parent in 2015.


•	A $1.8 million increase in repayments of long-term debt to our parent in 2015 related to a lease arrangement for rail cars.


•	A $1.7 million increase in dividends paid to our parent in 2015.

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 six months ended June 30, 2015.

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Credit Ratings

Access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

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.

Future Capital Requirements and Resources

Contractual Obligations

Our total contractual obligations and other commercial commitments were $3,892.5 million as of June 30, 2015, compared with $4,073.8 million as of December 31, 2014.

Capital Requirements

In our previously filed Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, we disclosed projected capital expenditures of $1.2 billion for 2015 through 2017 (including amounts already expended in 2015). This projection included approximately $320.0 million of capital expenditures associated with the potential addition of an electric generator at the Fox Energy Center site, which are currently under review as a result of the order from the PSCW approving the WEC Merger. See Management's Discussion and Analysis of Financial Condition and Results of Operations – Other Future Considerations for more information. In addition, all of our projected capital expenditures are being reviewed in connection with the WEC Merger.

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 Holding. 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.

At June 30, 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

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 $517.0 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 June 2015, we withdrew our application for a Certificate of Public Convenience and Necessity in compliance with a May 2015 order from the PSCW approving the WEC Merger. We and Wisconsin Electric Power Company (Wisconsin Electric Power) expect to submit to the PSCW a joint integrated resource plan for our combined loads during the third quarter of 2015 in order for the PSCW to further evaluate the need for the potential new unit.

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Presque Isle System Support Resource (SSR) Costs

In August 2013, 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 will compensate Wisconsin Electric Power by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load-serving entities, including us, based on load ratio share within the ATC footprint. In May 2015, MISO made a compliance filing regarding the allocation of Presque Isle SSR costs, and did not allocate any of these SSR costs to us. This and several other FERC dockets and rehearing requests regarding the amount and allocation of Presque Isle SSR costs are still pending.

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 WEC Merger. In April 2015, the FERC approved the termination of the SSR agreement effective February 1, 2015.

Based on the currently approved allocation method, no SSR costs would be required for WPS for the SSR-designated period, which ended February 1, 2015. A potential reallocation of the Presque Isle SSR costs based on the pending FERC dockets and rehearing requests may result in a change. If any SSR costs are allocated to WPS, costs related to retail customers will be deferred based on an order from the PSCW. The appropriate ratemaking treatment will be determined by the PSCW after December 31, 2015. Costs for Michigan customers would be recovered through the Power Supply Cost Recovery mechanism, and costs for wholesale customers would be recovered through formula rates.

MISO Transmission Owner Return on Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting, among other things, to reduce the base return on equity (ROE) used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. However, the FERC denied all other aspects of the complaint, including that the use of capital structures that include more than 50% common equity is unjust and unreasonable. 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, 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.

Climate Change

On August 3, 2015, the EPA issued final guidelines relating to greenhouse gas (GHG) emissions from existing generating units, and published final performance standards for modified and reconstructed generating units and new fossil fueled power plants. The final guidelines for existing fossil generating units seek to attain state-specific GHG rate limits by 2030, and require states to submit plans as early as September 2016. States requesting an extension would be required to submit final plans by September 2018, either alone or in cooperation with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking aggressive GHG reductions in Wisconsin and Michigan. The proposed program consists of building blocks that include a combination of power plant efficiency improvements, increased reliance on combined cycle gas units, and adding new renewable energy resources.

We are in the process of reviewing the final guidelines for existing generating units to determine the potential impacts to our operations, but these guidelines could result in significant additional compliance costs, including capital expenditures, impact how we operate our existing fossil fueled power plants, and could have a material adverse impact on our operating costs. In addition, several states have indicated that they intend to challenge these new rules, and any state compliance plans that are developed could be subject to change based upon the outcome of this litigation.

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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, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure.

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 June 30, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2015, the WEC Merger was completed. WEC is currently in the process of integrating our operations, processes, and internal controls. See Note 2, WEC Merger, for more information.

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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

Other than the inapplicability of the "Risk Related to the Proposed Merger of Integrys Energy Group with Wisconsin Energy Corporation (Wisconsin Energy)," which has been replaced with the risks set forth below, 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.

Risks Related to the WEC Merger

The WEC Merger may not achieve its anticipated results, and we may be unable to integrate our operations as expected.

The WEC Merger Agreement was entered into with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of the two companies can be integrated in an efficient, effective, and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees; the disruption of each company's ongoing businesses, processes, and systems; or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the transaction as and when expected. We may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects.

The acquisition may adversely affect our ability to attract and retain key employees.

Current and prospective employees may experience uncertainty about their future roles at the company as a result of the merger. In addition, current and prospective employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect our ability to attract and retain key management and other personnel.

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

Dividend Restrictions

Integrys Holding 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 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:	August 5, 2015	/s/ Stephen P. Dickson
		Stephen P. Dickson
		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 JUNE 30, 2015



Exhibit No.		Description

3.1		Amendment to the By-Laws of WPS. (Incorporated by reference to Exhibit 3.1 to WPS's June 29, 2015 Form 8-K.)

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 WPS.

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 WPS.

32.1		Written Statement of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350 for WPS.

32.2		Written Statement of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS.

101		Financial statements from the Quarterly Report on Form 10-Q of WPS for the quarter ended June 30, 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.

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

Attached files

WISCONSIN PUBLIC SERVICE CORP Reports