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EX-12.1 - WISCONSIN PUBLIC SERVICE EXHIBIT 12.1 - WISCONSIN PUBLIC SERVICE CORPa2015q3wps10-qexhibit121.htm
EX-31.1 - WISCONSIN PUBLIC SERVICE EXHIBIT 31.1 - WISCONSIN PUBLIC SERVICE CORPa2015q3wps10-qexhibit311.htm
EX-32.1 - WISCONSIN PUBLIC SERVICE EXHIBIT 32.1 - WISCONSIN PUBLIC SERVICE CORPa2015q3wps10-qexhibit321.htm
EX-32.2 - WISCONSIN PUBLIC SERVICE EXHIBIT 32.2 - WISCONSIN PUBLIC SERVICE CORPa2015q3wps10-qexhibit322.htm
EX-31.2 - WISCONSIN PUBLIC SERVICE EXHIBIT 31.2 - WISCONSIN PUBLIC SERVICE CORPa2015q3wps10-qexhibit312.htm

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549 

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2015


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
September 30, 2015

All of the common stock of Wisconsin Public Service Corporation is owned by Integrys Holding, Inc.

 



WISCONSIN PUBLIC SERVICE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2015
TABLE OF CONTENTS

 
 
Page
 
 
 
 
 
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



i


GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates
ATC
 
American Transmission Company LLC
Integrys
 
Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
WBS
 
WEC Business Services, LLC
WEC Energy Group
 
WEC Energy Group, Inc.
Wisconsin Electric
 
Wisconsin Electric Power Company
WRPC
 
Wisconsin River Power Company
 
 
 
Federal and State Regulatory Agencies
EPA
 
United States Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
MPSC
 
Michigan Public Service Commission
PSCW
 
Public Service Commission of Wisconsin
SEC
 
United States Securities and Exchange Commission
WDNR
 
Wisconsin Department of Natural Resources
 
 
 
Accounting Terms
AFUDC
 
Allowance for Funds Used During Construction
ASU
 
Accounting Standards Update
FASB
 
Financial Accounting Standards Board
GAAP
 
United States Generally Accepted Accounting Principles
OPEB
 
Other Postretirement Employee Benefits
 
 
 
Environmental Terms
BTA
 
Best Technology Available
EM
 
Entrainment Mortality
GHG
 
Greenhouse Gas
IM
 
Impingement Mortality
MATS
 
Mercury and Air Toxics Standards
NAAQS
 
National Ambient Air Quality Standards
SO2
 
Sulfur Dioxide
 
 
 
Measurements
MW
 
Megawatt (One MW equals one million Watts)
MWh
 
Megawatt-hour
 
 
 
Other Terms and Abbreviations
Exchange Act
 
Securities Exchange Act of 1934, as amended
FTRs
 
Financial Transmission Rights
IES
 
Integrys Energy Services, Inc.
Merger Agreement
 
Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys and Wisconsin Energy Corporation
MISO
 
Midcontinent Independent System Operator, Inc.
N/A
 
Not Applicable
ROE
 
Return on Equity
SSR
 
System Support Resource
UPPCO
 
Upper Peninsula Power Company


ii


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, dividend payout ratios, effective tax rate, projections related to the pension and other postretirement benefit plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2014, and the following:

Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, changes in the cost or availability of materials needed to operate environmental controls at our electric generating facilities, and electric transmission or natural gas pipeline system constraints;

Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

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

The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

The timely completion of capital projects within budgets, as well as the recovery of those costs through rates;

The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, tax law changes, including the extension of bonus depreciation, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates;

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, the enforcement of these laws and regulations, changes in the interpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;

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



1


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

Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;

The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;

The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

Advances in technology that result in competitive disadvantages and create the potential for impairment of existing assets;

The terms and conditions of the governmental and regulatory approvals of WEC Energy Group's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;

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

The effect of accounting pronouncements issued periodically by standard-setting bodies; and

Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.


2


PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
 
Three Months Ended
 
Nine Months Ended
 
 
September 30
 
September 30
(in millions)
 
2015
 
2014
 
2015
 
2014
Operating revenues
 
$
390.8

 
$
370.9

 
$
1,146.1

 
$
1,285.9

 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Cost of sales
 
141.4

 
138.6

 
466.3

 
593.5

Other operation and maintenance
 
120.3

 
116.0

 
356.0

 
374.4

Depreciation and amortization
 
30.4

 
29.6

 
90.5

 
87.0

Property and revenue taxes
 
10.2

 
9.0

 
30.7

 
29.6

Total operating expenses
 
302.3

 
293.2

 
943.5

 
1,084.5

 
 
 
 
 
 
 
 
 
Operating income
 
88.5

 
77.7

 
202.6

 
201.4

 
 
 
 
 
 
 
 
 
Other income, net
 
6.7

 
5.8

 
19.8

 
20.1

Interest expense
 
13.2

 
14.6

 
40.3

 
42.9

Other expense
 
(6.5
)
 
(8.8
)
 
(20.5
)
 
(22.8
)
 
 
 
 
 
 
 
 
 
Income before taxes
 
82.0

 
68.9

 
182.1

 
178.6

Income tax expense
 
31.0

 
26.0

 
67.9

 
66.7

Net income
 
51.0

 
42.9

 
114.2

 
111.9

 
 
 
 
 
 
 
 
 
Preferred stock dividend requirements
 
(0.7
)
 
(0.7
)
 
(2.3
)
 
(2.3
)
Net income attributed to common shareholder
 
$
50.3

 
$
42.2

 
$
111.9

 
$
109.6


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

3


WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
 
September 30
 
December 31
(in millions, except share and per share amounts)
 
2015
 
2014
Assets
 
 

 
 

Current assets
 
 
 
 
Cash and cash equivalents
 
$
2.9

 
$
5.4

Accounts receivable and unbilled revenue, net of reserves of $4.5 and $3.2, respectively
 
159.8

 
203.1

Receivables from related parties
 
1.5

 
1.3

Inventories
 
 

 
 
Fuel and natural gas
 
90.3

 
85.0

Materials and supplies, at average cost
 
42.2

 
39.2

Prepaid taxes
 
31.0

 
65.7

Other current assets
 
27.0

 
18.3

Current assets
 
354.7

 
418.0

 
 
 
 
 
Long-term assets
 
 
 
 
Property, plant, and equipment, net of accumulated depreciation of $1,560.1 and $1,542.5, respectively
 
3,331.7

 
3,131.0

Regulatory assets
 
466.6

 
457.1

Goodwill
 
36.4

 
36.4

Pension and other postretirement benefit assets
 
146.3

 
128.9

Other long-term assets
 
103.6

 
107.3

Long-term assets
 
4,084.6

 
3,860.7

Total assets
 
$
4,439.3

 
$
4,278.7

 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 

 
 
Current liabilities
 
 
 
 
Short-term debt
 
$
102.1

 
$
145.1

Current portion of long-term debt
 
125.0

 
125.0

Current portion of long-term debt to parent
 
3.0

 
2.5

Accounts payable
 
202.0

 
161.6

Payables to related parties
 
19.7

 
16.9

Other current liabilities
 
79.0

 
75.4

Current liabilities
 
530.8

 
526.5

 
 
 
 
 
Long-term liabilities
 
 
 
 
Long-term debt to parent
 

 
2.9

Long-term debt
 
1,049.6

 
1,049.5

Deferred income taxes
 
767.9

 
722.1

Deferred investment tax credits
 
7.5

 
7.8

Regulatory liabilities
 
315.4

 
318.4

Environmental remediation liabilities
 
86.1

 
86.3

Pension and other postretirement benefit obligations
 
40.1

 
37.6

Payables to related parties
 
4.9

 
5.4

Other long-term liabilities
 
80.2

 
71.6

Long-term liabilities
 
2,351.7

 
2,301.6

 
 
 
 
 
Commitments and contingencies (note 6)
 


 


 
 
 
 
 
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
 
863.4

 
782.0

Retained earnings
 
546.6

 
521.8

Total liabilities and shareholders’ equity
 
$
4,439.3

 
$
4,278.7


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

4


WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION (Unaudited)
 
September 30
 
December 31
(in millions, except share and per share amounts)
 
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
 
863.4

 
782.0

Retained earnings
 
546.6

 
521.8

Total common stock equity
 
1,505.6

 
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

 
3.0

 
3.4

Total
 
 
 
 
 
3.0

 
5.4

Current portion of long-term debt to parent
 
 
 
 
 
(3.0
)
 
(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
 
 

 
 

 
$
2,606.4

 
$
2,503.0


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

5


WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
 
Nine Months Ended
 
 
September 30
(in millions)
 
2015
 
2014
Operating Activities
 
 

 
 

Net income
 
$
114.2

 
$
111.9

Reconciliation to cash provided by operating activities
 
 

 
 

Depreciation and amortization expense
 
91.9

 
85.9

Deferred income taxes and investment tax credits, net
 
36.8

 
52.1

Contributions to pension and other postretirement plans
 
(0.9
)
 
(46.7
)
Change in
 
 

 
 
Accounts receivable and unbilled revenues
 
40.9

 
45.0

Inventories
 
(4.1
)
 
(25.6
)
Other current assets
 
21.7

 
40.1

Accounts payable
 
(5.4
)
 
(10.3
)
Other current liabilities
 
24.9

 
(8.3
)
Other, net
 

 
(16.1
)
Net cash provided by operating activities
 
320.0

 
228.0

 
 
 
 
 
Investing Activities
 
 

 
 

Capital expenditures
 
(265.6
)
 
(215.8
)
Cost of removal, net of salvage
 
(2.7
)
 
(2.1
)
Other, net
 
(1.6
)
 
(0.7
)
Net cash used in investing activities
 
(269.9
)
 
(218.6
)
 
 
 
 
 
Financing Activities
 
 

 
 

Preferred stock dividend requirements
 
(2.3
)
 
(2.3
)
Short-term debt, net
 
(43.0
)
 
37.4

Payments of long-term debt to parent
 
(2.4
)
 
(0.6
)
Dividends to parent
 
(86.3
)
 
(83.9
)
Equity contribution from parent
 
85.0

 
40.0

Other
 
(3.6
)
 
(2.1
)
Net cash used in financing activities
 
(52.6
)
 
(11.5
)
 
 
 
 
 
Net change in cash and cash equivalents
 
(2.5
)
 
(2.1
)
Cash and cash equivalents at beginning of period
 
5.4

 
5.7

Cash and cash equivalents at end of period
 
$
2.9

 
$
3.6

 
 
 
 
 
Cash paid for interest
 
$
29.2

 
$
27.9

Cash received for income taxes
 
$
(13.2
)
 
$
(5.1
)

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

6


WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2015

NOTE 1—GENERAL INFORMATION

On June 29, 2015, our parent company, Integrys, was acquired by Wisconsin Energy Corporation, and the combined company was renamed WEC Energy Group, Inc. In this report, when we refer to the "WEC Merger," we are referring to this acquisition. See Note 2, WEC Merger, for more information on the acquisition.

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 Wisconsin Public Service Corporation.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2014. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2015, are not necessarily indicative of expected results for 2015 due to seasonal variations and other factors.

Our balance sheet reflects the historical basis of our assets and liabilities, as WEC Energy Group 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, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

Reclassifications

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

Statements of Income

Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net.

Payroll taxes of $2.1 million and $6.7 million for the three and nine months ended September 30, 2014, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes.

Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $1.6 million and $4.6 million for the three and nine months ended September 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, at December 31, 2014.

Current regulatory liabilities of $6.1 million and $15.1 million were reclassified to other current liabilities and long-term regulatory liabilities, respectively, at December 31, 2014.


7


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 Energy Group. The acquisition 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 Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time.

We do not believe that the conditions set forth in the various regulatory orders approving the WEC Merger will have a material impact on our operations or financial results.

NOTE 3—CASH AND CASH EQUIVALENTS

Accounts payable related to construction costs totaled $74.9 million and $56.2 million for the nine months ended September 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 nine months ended September 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.
 
 
September 30, 2015
 
December 31, 2014
(in millions)
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Amortized intangible assets *
 
$
15.6

 
$
(6.7
)
 
$
8.9

 
$
15.6

 
$
(4.3
)
 
$
11.3

Unamortized intangible assets
 
0.4

 

 
0.4

 

 

 

Total intangible assets
 
$
16.0

 
$
(6.7
)
 
$
9.3

 
$
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 September 30, 2015, was approximately three years.

NOTE 5—SHORT-TERM DEBT AND LINES OF CREDIT

Our outstanding short-term borrowings were as follows:
(in millions, except percentages)
 
September 30, 2015
 
December 31, 2014
Commercial paper
 
$
102.1

 
$
145.1

Average interest rate on commercial paper outstanding
 
0.29
%
 
0.32
%

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2015, was $141.4 million with a weighted-average interest rate during the period of 0.29%.

8


We manage our liquidity by maintaining what we believe to be 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:
(in millions)
 
Maturity
 
September 30, 2015
Revolving credit facility
 
June 2017
 
$
115.0

Revolving credit facility
 
May 2019
 
135.0

Total short-term credit capacity
 
 
 
$
250.0

 
 
 
 
 
Less:
 
 
 
 

Commercial paper outstanding
 
 
 
102.1

Available capacity under existing agreements
 
 
 
$
147.9


NOTE 6—COMMITMENTS AND CONTINGENCIES

Unconditional Purchase Obligations

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. Our minimum future commitments related to these purchase obligations as of September 30, 2015, was $1,137.5 million.

Environmental Matters

We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal/landfill sites. We perform ongoing assessments of these sites.

Air Quality

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a 1-Hour SO2 NAAQS that became effective in August 2010. In August 2015, the EPA issued the Data Requirements Rule that established procedures and timelines for implementation of the revised standard.

The rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area is classified as nonattainment. A plan would need to be developed requiring emission reductions to allow attainment 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 the EPA had agreed upon in May 2014. This consent decree has 1-Hour SO2 implementation dates that are sooner than the Data Requirements Rule.

We believe our fleet is well positioned to meet this regulation once it is finalized.


9


8-Hour Ozone National Ambient Air Quality Standard

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to lower the NAAQS. In October 2015, the EPA released the final rule, which effectively lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. We will be required to comply with the new reduction requirements no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

In December 2011, the EPA issued the final MATS rule, 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 that require a 90% reduction of mercury. In June 2015, the United States 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.  

Our compliance plans currently include capital projects for our jointly owned plants to achieve the required reductions for MATS and the state mercury rules. We are working on the addition of a multi-pollutant control technology at Weston Unit 3. Controls for acid gases and mercury were also installed at the Pulliam units. We received a one year MATS compliance extension for Weston Unit 3 from the WDNR.

Climate Change

In August 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and require states to submit plans as early as September 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction 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 GHG emission reductions in Wisconsin of 41% below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources.

We are in the process of reviewing the final rule for existing generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants, and could have a material adverse impact on our operating costs. In October 2015, following publication of the final rule, numerous states (including Wisconsin), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. Any state or federal compliance plans that are developed could be subject to change based upon the outcome of this litigation.

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 entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the U.S. District Court for the Eastern District of Wisconsin in March 2013.

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.

10



Columbia and Edgewater CAA Issues

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the owner and operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, Wisconsin Electric (former co-owner of an Edgewater unit), 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, Madison Gas and Electric, and Wisconsin Electric entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013.

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.

Weston Title V Air Permit Issues

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, 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 Unit 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 has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. Impacts are both from entrainment (larvae, eggs, and small fry being drawn into cooling water systems) and impingement (larger fish being pinned against cooling water intake structures). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures.

Facility owners must select from seven compliance options available to meet the IM reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR to address EM reduction on a site-specific basis taking into consideration several factors. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8 and Weston Units 2 through 4. 

11



During 2015-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Weston Units 3 and 4 (units have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued the final steam electric effluent guidelines rule, which governs discharges of wastewater from our power plant processes in Wisconsin. The WDNR will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Pulliam Units 7 and 8 and Weston Unit 3.

Land Quality

Coal Combustion Residuals Rule

In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. 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. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources.

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. 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 Program. We are also working with various state jurisdictions in our investigation and remediation planning. All sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of the sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring 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 and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We established the following regulatory assets and reserves related to manufactured gas plant sites:
(in millions)
 
September 30, 2015
 
December 31, 2014
Regulatory assets
 
$
104.5

 
$
102.3

Reserves for future remediation
 
86.1

 
86.3



12


See Note 15, Commitments and Contingencies, in Item 8 of our 2014 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

NOTE 7—EMPLOYEE BENEFIT PLANS

The following table shows the components of net periodic pension and other postretirement employee benefits (OPEB) costs for our benefit plans:
 
 
Pension Costs
 
OPEB Costs
 
 
Three Months Ended September 30
 
Nine Months Ended September 30
 
Three Months Ended September 30
 
Nine Months Ended September 30
(in millions)
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
2.6

 
$
2.2

 
$
8.0

 
$
6.5

 
$
2.2

 
$
1.9

 
$
6.5

 
$
5.8

Interest cost
 
8.0

 
8.6

 
23.8

 
25.8

 
2.6

 
2.7

 
7.8

 
8.8

Expected return on plan assets
 
(16.3
)
 
(16.0
)
 
(48.7
)
 
(48.0
)
 
(4.0
)
 
(4.0
)
 
(12.0
)
 
(12.0
)
Loss on plan settlement
 

 

 
0.1

 
0.4

 

 

 

 

Amortization of prior service cost (credit)
 
0.1

 
0.1

 
0.2

 
0.4

 
(2.3
)
 
(2.3
)
 
(6.9
)
 
(5.7
)
Amortization of net actuarial loss
 
5.3

 
3.7

 
15.8

 
11.2

 
0.8

 
0.7

 
2.7

 
2.0

Net periodic benefit cost (credit)
 
$
(0.3
)
 
$
(1.4
)
 
$
(0.8
)
 
$
(3.7
)
 
$
(0.7
)
 
$
(1.0
)
 
$
(1.9
)
 
$
(1.1
)

In March 2014, we remeasured the obligations of certain OPEB 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 8—COMMON EQUITY

Stock-Based Compensation

Our employees were granted awards under Integrys’s stock-based compensation plans. Per the Merger Agreement, immediately prior to completion of the acquisition, 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 acquisition.

The intrinsic values of the awards canceled due to the acquisition 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 nine months ended September 30:
 
 
Three Months Ended September 30
 
Nine Months Ended September 30
(in millions)
 
2015
 
2014
 
2015
 
2014
Stock options
 
$

 
$
0.1

 
$

 
$
0.4

Performance stock rights
 

 
0.1

 
1.3

 
3.9

Restricted share units
 

 
0.7

 
3.5

 
2.7

Total stock-based compensation expense
 
$

 
$
0.9

 
$
4.8

 
$
7.0

Deferred income tax benefit
 
$

 
$
0.4

 
$
1.9

 
$
2.8



13


A summary of the activity for our stock-based compensation awards for the nine months ended September 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 September 30, 2015
 

 

 


*
The intrinsic value of restricted stock 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.

Restrictions

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.

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 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'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. See Note 15, Subsequent Events, for information regarding the redemption of our preferred stock.

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%.

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

Integrys 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 WEC Energy Group, Integrys, or their other subsidiaries.

NOTE 9—DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by the PSCW and the MPSC.


14


We record derivative instruments on the balance sheet as an asset or liability measured at fair value. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

The following table shows our derivative assets and derivative liabilities:
 
 
 
 
September 30, 2015
 
December 31, 2014
(in millions)
 
Balance Sheet Presentation 
 
Derivative Assets
 
Derivative Liabilities
 
Derivative Assets
 
Derivative Liabilities
Natural gas
 
Other current
 
$
0.3

 
$
1.0

 
$
0.1

 
$
2.1

Natural gas
 
Other long-term
 

 
0.1

 

 
0.1

FTRs
 
Other current
 
3.3

 

 
2.2

 
0.3

Petroleum products
 
Other current
 

 
0.3

 

 
1.1

Coal
 
Other current
 

 
3.4

 

 
2.4

Coal
 
Other long-term
 

 
2.4

 

 
1.0

 
 
Other current
 
3.6

 
4.7

 
2.3

 
5.9

 
 
Other long-term
 

 
2.5

 

 
1.1

Total
 
 
 
$
3.6

 
$
7.2

 
$
2.3

 
$
7.0


Gains (losses) on derivative instruments are primarily included in cost of sales on the condensed consolidated income statements. Our estimated notional volumes and gains (losses) were as follows:
 
 
Three Months Ended September 30, 2015
 
Three Months Ended September 30, 2014
(in millions)
 
Volume
 
Gains (Losses)
 
Volume
 
Gains (Losses)
Natural Gas
 
3.7 Dth
 
$
(0.7
)
 
3.1 Dth
 
$
(0.6
)
Petroleum products
 
1.5 gallons
 
(0.4
)
 
1.6 gallons
 

FTRs
 
2.5 MWh
 
1.6

 
2.2 MWh
 
1.3

Total
 
 
 
$
0.5

 
 
 
$
0.7


 
 
Nine Months Ended September 30, 2015
 
Nine Months Ended September 30, 2014
(in millions)
 
Volume
 
Gains (Losses)
 
Volume
 
Gains
Natural Gas
 
14.9 Dth
 
$
(3.2
)
 
14.1 Dth
 
$
1.2

Petroleum products
 
4.7 gallons
 
(1.4
)
 
4.2 gallons
 

FTRs
 
6.8 MWh
 
1.4

 
6.4 MWh
 
3.2

Total
 
 
 
$
(3.2
)
 
 
 
$
4.4


The amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2015, and December 31, 2014, we had posted collateral of $17.0 million and $6.6 million, respectively, in our margin accounts. These amounts are recorded on the condensed consolidated balance sheets in other current assets.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the condensed consolidated balance sheet:
 
 
September 30, 2015
 
December 31, 2014
 
 
Derivative
 
Derivative
 
Derivative
 
Derivative
(in millions)
 
Assets
 
Liabilities
 
Assets
 
Liabilities
Gross amount recognized on the balance sheet
 
$
3.6

 
$
7.2

 
$
2.3

 
$
7.0

Gross amount not offset on balance sheet *
 
(0.3
)
 
(1.4
)
 
(0.4
)
 
(3.6
)
Net Amount
 
$
3.3

 
$
5.8

 
$
1.9

 
$
3.4


*
Includes cash collateral posted of $1.1 million and $3.2 million as of September 30, 2015, and December 31, 2014, respectively.


15


NOTE 10—FAIR VALUE MEASUREMENTS

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).

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 methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets and liabilities 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.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
 
 
September 30, 2015
(in millions)
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative Assets
 
 

 
 

 
 

 
 

Natural gas contracts
 
$
0.3

 
$

 
$

 
$
0.3

FTRs
 

 

 
3.3

 
3.3

Total Derivative Assets
 
$
0.3

 
$

 
$
3.3

 
$
3.6

 
 
 
 
 
 
 
 
 
Derivative Liabilities
 
 

 
 

 
 

 
 

Natural gas contracts
 
$
1.1

 
$

 
$

 
$
1.1

Petroleum products contracts
 
0.3

 

 

 
0.3

Coal contracts
 

 
0.4

 
5.4

 
5.8

Total Derivative Liabilities
 
$
1.4

 
$
0.4

 
$
5.4

 
$
7.2



16


 
 
December 31, 2014
(in millions)
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative Assets
 
 
 
 
 
 
 
 
   Natural gas contracts
 
$

 
$
0.1

 
$

 
$
0.1

FTRs
 

 

 
2.2

 
2.2

Total Derivative Assets
 
$

 
$
0.1

 
$
2.2

 
$
2.3

 
 
 
 
 
 
 
 
 
Derivative Liabilities
 
 
 
 
 
 
 
 
   Natural gas contracts
 
$
2.2

 
$

 
$

 
$
2.2

FTRs
 

 

 
0.3

 
0.3

   Petroleum products contracts
 
1.1

 

 

 
1.1

Coal contracts
 

 
1.2

 
2.2

 
3.4

Total Derivative Liabilities
 
$
3.3

 
$
1.2

 
$
2.5

 
$
7.0


The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO market.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
 
 
Three Months Ended September 30
 
Nine Months Ended September 30
(in millions)
 
2015
 
2014
 
2015
 
2014
Balance at the beginning of period
 
$
(1.3
)
 
$
4.9

 
$
(0.3
)
 
$
(1.3
)
Net realized and unrealized gains (losses)
 
0.2

 
(0.4
)
 
(11.2
)
 
3.5

Purchases
 

 

 
9.8

 
4.3

Settlements
 
(1.0
)
 
(1.5
)
 
(0.4
)
 
(3.5
)
Balance at the end of period
 
$
(2.1
)
 
$
3.0

 
$
(2.1
)
 
$
3.0


Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the condensed consolidated statements of income.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our condensed consolidated balance sheets that are not recorded at fair value:
 
 
September 30, 2015
 
December 31, 2014
(in millions)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt
 
$
1,175.1

 
$
1,221.7

 
$
1,175.1

 
$
1,286.2

Long-term debt to parent
 
3.0

 
3.1

 
5.4

 
5.7

Preferred stock
 
51.2

 
51.8

 
51.2

 
52.0


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. The fair values of long-term debt, including the current portion of long-term debt, but excluding unamortized discount on debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, when available, or by using a perpetual dividend discount model.

NOTE 11—REGULATORY ENVIRONMENT

2016 Wisconsin 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 10.2% ROE and a common equity component

17


of 50.52%. The proposed retail electric rate increase is primarily driven by the expected completion in 2016 of the ReACT™ emission control technology at Weston Unit 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 forecasted retail electric and natural gas revenues and employee benefit costs.

In October 2015, we adjusted our requested retail electric rate increase to $48.0 million and our requested retail natural gas rate increase to $4.4 million. The revised requests are primarily driven by updates to fuel and purchased power costs, the cost of natural gas, payroll expense, employee benefit costs, and electric transmission expense. At the same time, we offered a two year earnings sharing mechanism to address concerns about acquisition-related benefits. Under the terms of our proposal, if we earn above our authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and used to reduce a deferral for ReACT™ if approved by the PSCW. If approved, we would defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level until the next rate case. All utility earnings above the first 50 basis points will be solely used to reduce the deferral.

2015 Wisconsin 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 10.2% ROE. The order also included a common equity component of 50.28%. The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014.

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 Units 5 and 6 and Weston Unit 1 starting with the actual retirement date in 2015 and concluding by 2023. See Note 6, Commitments and Contingencies, for more information. The PSCW is allowing us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent tolerance window.

The retail natural gas rate decrease was driven by the approximate $16.0 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.

2015 Michigan Rates

In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. 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 10.2% ROE and a common equity component of 50.48%. 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 Unit 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 Units 5 and 6 and Weston Unit 1 starting with the actual

18


retirement date in 2015 and concluding by 2023. Lastly, we will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

NOTE 12—SEGMENTS OF BUSINESS

At September 30, 2015, we reported three segments. Our principal business segments are our regulated electric utility operations and our regulated natural gas utility operations. Our other segment includes nonutility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC.

The tables below present information related to our reportable segments:
 
 
Regulated
 
 
 
 
 
 
(in millions)
 
Electric Utility
 
Natural Gas Utility
 
Total Utility
 
Other
 
Reconciling Eliminations
 
WPS Consolidated
Three Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
External revenues
 
$
346.5

 
$
44.3

 
$
390.8

 
$

 
$

 
$
390.8

Intersegment revenues
 

 
3.7

 
3.7

 
0.2

 
(3.9
)
 

Depreciation and amortization
 
26.0

 
4.3

 
30.3

 
0.1

 

 
30.4

Operating income
 
84.9

 
3.5

 
88.4

 
0.1

 

 
88.5

Interest expense
 
10.6

 
2.5

 
13.1

 
0.1

 

 
13.2


 
 
Regulated
 
 
 
 
 
 
(in millions)
 
Electric Utility
 
Natural Gas Utility
 
Total Utility
 
Other
 
Reconciling Eliminations
 
WPS Consolidated
Three Months Ended September 30, 2014
 
 
 
 

 
 

 
 

 
 

 
 

External revenues
 
$
327.9

 
$
43.0

 
$
370.9

 
$

 
$

 
$
370.9

Intersegment revenues
 

 
3.4

 
3.4

 
0.3

 
(3.7
)
 

Depreciation and amortization
 
25.5

 
4.1

 
29.6

 
0.1

 
(0.1
)
 
29.6

Operating income (loss)
 
80.2

 
(2.7
)
 
77.5

 
0.2

 

 
77.7

Interest expense
 
11.4

 
2.6

 
14.0

 
0.6

 

 
14.6


 
 
Regulated
 
 
 
 
 
 
(in millions)
 
Electric Utility
 
Natural Gas Utility
 
Total Utility
 
Other
 
Reconciling Eliminations
 
WPS Consolidated
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
External revenues
 
$
920.1

 
$
226.0

 
$
1,146.1

 
$

 
$

 
$
1,146.1

Intersegment revenues
 

 
8.4

 
8.4

 
0.6

 
(9.0
)
 

Depreciation and amortization
 
77.5

 
12.7

 
90.2

 
0.3

 

 
90.5

Operating income
 
179.3

 
23.3

 
202.6

 

 

 
202.6

Interest expense
 
32.4

 
7.7

 
40.1

 
0.2

 

 
40.3


 
 
Regulated
 
 
 
 
 
 
(in millions)
 
Electric Utility
 
Natural Gas Utility
 
Total Utility
 
Other
 
Reconciling Eliminations
 
WPS Consolidated
Nine Months Ended September 30, 2014
 
 
 
 

 
 

 
 

 
 

 
 

External revenues
 
$
941.2

 
$
344.7

 
$
1,285.9

 
$

 
$

 
$
1,285.9

Intersegment revenues
 

 
10.5

 
10.5

 
1.0

 
(11.5
)
 

Depreciation and amortization
 
74.7

 
12.2

 
86.9

 
0.5

 
(0.4
)
 
87.0

Operating income
 
164.3

 
36.7

 
201.0

 
0.4

 

 
201.4

Interest expense
 
33.5

 
7.8

 
41.3

 
1.6

 

 
42.9


NOTE 13—RELATED PARTY TRANSACTIONS

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

19



We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the WEC Merger on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WEC Business Services, LLC (WBS), and a new affiliated interest agreement (Non-WBS AIA) went into effect. The new Non-WBS AIA includes the former Wisconsin Energy Corporation and its subsidiaries. It governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries under new interim WBS affiliated interest agreements (interim WBS AIAs). The Non-WBS AIA includes no other significant changes from the prior Non-IBS affiliated interest agreement. The PSCW and two other state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA. Approval of the Non-WBS AIA is still needed from the Minnesota Public Utilities Commission. The interim WBS AIAs have been approved by the PSCW.

The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016, sunset date for WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries. These companies may request one extension of the sunset date. Prior to the sunset date, WEC Energy Group will need to file new or modified Non-WBS and WBS AIAs for approval with the PSCW and other state commissions.

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

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

The table below includes information summarizing other transactions entered into with related parties:
(in millions)
 
September 30, 2015
 
December 31, 2014
Notes payable *
 
 

 
 

Integrys
 
$
3.0

 
$
5.4

Accounts payable
 
 

 
 

Network transmission services from ATC
 
8.4

 
8.2

Liability related to income tax allocation
 
 
 
 

Integrys
 
5.6

 
6.1


*
WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys. At September 30, 2015, and December 31, 2014, the current portion of the note payable was $3.0 million and $2.5 million, respectively.

In addition to the above transactions, Integrys had a $20.0 million parental guarantee at September 30, 2015, related to an interconnection agreement between ATC and us. This guarantee is not reflected on our condensed consolidated balance sheets.

20



The following table shows activity associated with related party transactions:
 
 
Three Months Ended September 30
 
Nine Months Ended September 30
(in millions)
 
2015
 
2014
 
2015
 
2014
Electric transactions
 
 

 
 

 
 

 
 

Sales to UPPCO (1)
 
$

 
$
4.1

 
$

 
$
15.3

Sales to Integrys Transportation Fuels, LLC
 

 
0.1

 

 
0.1

Natural gas transactions
 
 
 
 

 
 
 
 

Sales to Wisconsin Electric
 
0.3

 

 
0.3

 

Sales to IES (2)
 

 
0.3

 

 
0.5

Purchases from IES (2)
 

 
0.1

 

 
2.5

Interest expense (3)
 
 

 
 

 
 
 
 

Integrys
 

 
0.2

 
0.2

 
0.4

Transactions with equity method investees
 
 

 
 

 
 
 
 

Charges from ATC for network transmission services
 
25.3

 
24.7

 
76.0

 
74.2

Charges to ATC for services and construction
 
2.9

 
2.4

 
7.5

 
7.5

Purchases of energy from WRPC
 
1.0

 
0.9

 
3.1

 
3.0

Charges to WRPC for operations
 
0.5

 
0.3

 
1.0

 
1.0

Equity earnings from WPS Investments, LLC (4)
 
2.5

 
2.6

 
6.8

 
7.7

Sales of electricity to AMP Trillium, LLC (5)
 

 

 
0.1

 


(1) 
Integrys sold UPPCO in August 2014.

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

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

(4) 
WPS Investments, LLC is a consolidated subsidiary of Integrys that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At September 30, 2015, we had a 10.87% 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 to WPS Investments, LLC.

(5) 
AMP Trillium, LLC is a joint venture between Integrys Transportation Fuels, LLC, a subsidiary of Integrys, and AMP Americas, LLC. This joint venture owns and operates compressed natural gas fueling stations.

NOTE 14—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. 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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption for fiscal years and interim periods beginning after December 15, 2016, permitted. The standard can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our consolidated financial statements.

Debt Issuance Costs

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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The standard requires retrospective application by restating each prior period presented in the financial statements. We are currently assessing the effects this guidance may have on our consolidated financial statements.


21


NOTE 15—SUBSEQUENT EVENTS

In October 2015, we announced the planned redemption of all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7-1/8% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption.  The scheduled date of redemption is November 13, 2015. Following this redemption, we will discharge our mortgage indenture and do not intend to issue additional first mortgage bonds under the mortgage indenture.

All $1,175.0 million of our senior notes outstanding are also secured by first mortgage bonds. On the redemption date of the 7-1/8% Series, the senior notes will become senior unsecured obligations and rank equally with all of our other unsecured and unsubordinated obligations.

In addition, on October 14, 2015, we issued notices of redemption for all 511,882 outstanding shares of our five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and, (v) 150,000 shares of 6.88% Series. The scheduled date of redemption is November 13, 2015. The aggregate redemption price is $52.8 million, plus accumulated and unpaid dividends.


22


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, Integrys, became a wholly owned subsidiary of WEC Energy Group. We are an electric and natural gas utility and a wholly owned subsidiary of Integrys. 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

THREE MONTHS ENDED SEPTEMBER 30, 2015
 
Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2015 with the third quarter of 2014, including favorable or better, "B", and unfavorable or worse, "W", variances:
 
 
Three Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Electric utility operations
 
$
48.0

 
$
4.9

 
$
43.1

Natural gas utility operations
 
0.7

 
3.7

 
(3.0
)
Other operations
 
1.6

 
(0.5
)
 
2.1

Net income attributed to common shareholder
 
$
50.3

 
$
8.1

 
$
42.2


Electric Utility Segment Contribution to Operating Income
 
 
Three Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Revenues
 
$
346.5

 
$
18.6

 
$
327.9

Fuel and purchased power
 
122.7

 
(8.1
)
 
114.6

Total electric margins
 
223.8

 
10.5

 
213.3

 
 
 
 
 
 
 
Other operation and maintenance
 
103.7

 
(4.5
)
 
99.2

Depreciation and amortization
 
26.0

 
(0.5
)
 
25.5

Property and revenue taxes
 
9.2

 
(0.8
)
 
8.4

Operating income
 
$
84.9

 
$
4.7

 
$
80.2



23


The following tables provide information on sales volumes by customer class and weather statistics:
 
 
Three Months Ended September 30
 
 
MWh (in thousands)
Electric Sales Volumes
 
2015
 
B (W)
 
2014
Customer class
 
 

 
 
 
 

Residential
 
775.7

 
65.3

 
710.4

Small commercial and industrial
 
1,090.1

 
61.2

 
1,028.9

Large commercial and industrial
 
1,056.8

 
31.8

 
1,025.0

Other
 
7.0

 

 
7.0

Total retail
 
2,929.6

 
158.3

 
2,771.3

Wholesale - other
 
738.9

 
(12.4
)
 
751.3

Resale
 
347.6

 
183.8

 
163.8

Total sales in MWh
 
4,016.1

 
329.7

 
3,686.4


 
 
Three Months Ended September 30
 
 
Degree Days
Weather *
 
2015

B (W)

2014
Heating (214 Normal)
 
120

 
(123
)
 
243

Cooling (359 Normal)
 
396

 
172

 
224


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

Operating Income

Operating income at the electric utility segment increased $4.7 million, driven by:

An $8.7 million increase in electric margins related to sales volume variances. Margins from residential and small commercial and industrial customers increased, primarily due to warmer weather and higher use per customer in the third quarter of 2015.

A $3.0 million increase in electric margins resulting from over-collections of actual fuel and purchased power costs as compared with costs approved in rates in 2015, as opposed to under-collections of actual costs as compared with costs approved in 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, and the remaining variance impacts margins.

These increases in operating income were partially offset by:

A $3.0 million increase in electric transmission expenses from MISO and ATC. This increase was partially driven by higher costs to meet ATC's revenue requirements as well as increased costs from MISO related to transmission providers' continued investment in equipment and facilities for improved reliability. Transmission expense in the third quarter of 2015 reflects only amounts included in 2015 rates due to the PSCW's approval of deferral treatment for incremental amounts.

A $2.0 million increase in maintenance expense, primarily due to a planned outage at the Fox Energy Center in the third quarter of 2015.

A $2.0 million decrease from electric margins 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 the higher cost of fuel for electric generation, which does not impact margins unless costs differ less than 2% from the amounts included in rates, as discussed above. See Note 11, Regulatory Environment, for more information.


24


Natural Gas Utility Segment Contribution to Operating Income
 
 
Three Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Revenues
 
$
48.0

 
$
1.6

 
$
46.4

Cost of natural gas sold
 
22.0

 
5.7

 
27.7

Total natural gas margins
 
26.0

 
7.3

 
18.7

 
 
 
 
 
 
 
Other operation and maintenance
 
17.1

 
(0.4
)
 
16.7

Depreciation and amortization
 
4.3

 
(0.2
)
 
4.1

Property and revenue taxes
 
1.1

 
(0.5
)
 
0.6

Operating income (loss)
 
$
3.5

 
$
6.2

 
$
(2.7
)

The following tables provide information on sales volumes by customer class and weather statistics:
 
 
Three Months Ended September 30
 
 
Therms (in millions)
Natural Gas Sales Volumes
 
2015
 
B (W)
 
2014
Customer class
 
 

 
 
 
 

Residential
 
13.6

 
(1.7
)
 
15.3

Commercial and industrial
 
17.7

 
1.2

 
16.5

Other
 
9.8

 
5.1

 
4.7

Total retail
 
41.1

 
4.6

 
36.5

Transport
 
75.5

 
5.7

 
69.8

Total sales in therms
 
116.6

 
10.3

 
106.3


 
 
Three Months Ended September 30
 
 
Degree Days
Weather *
 
2015
 
B (W)
 
2014
Heating (214 normal)
 
120

 
(123
)
 
243


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

Operating Income (Loss)

Operating income at the natural gas utility segment increased $6.2 million, driven by:

A $7.7 million increase in natural gas margins related to the PSCW rate order, effective January 1, 2015, including an approximate $4.8 million positive 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 higher cost recovery in periods of low sales volumes. In addition, although the PSCW approved a rate decrease in 2015, the majority of the decrease related to decoupling refunds to customers, which has no impact on margins. See Note 11, Regulatory Environment, for more information.

A partially offsetting $1.4 million increase in individually non-significant operating expenses, which include administrative and general salaries, property and revenue taxes, and maintenance.

Other Segment Operations
 
 
Three Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Operating income
 
$
0.1

 
$
(0.1
)
 
$
0.2



25


Consolidated Other Income, Net
 
 
Three Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
AFUDC - Equity
 
$
4.1

 
$
1.9

 
$
2.2

Equity in earnings of equity method investments
 
2.7

 
(0.2
)
 
2.9

Other, net
 
(0.1
)
 
(0.8
)
 
0.7

Other income, net
 
$
6.7

 
$
0.9

 
$
5.8


Other income, net increased by $0.9 million when compared to the third quarter of 2014, primarily due to an increase in AFUDC driven by the construction of the ReACTTM emission control technology at Weston Unit 3.

Consolidated Interest Expense
 
 
Three Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Interest expense
 
$
13.2

 
$
1.4

 
$
14.6


Interest expense decreased by $1.4 million when compared to the third quarter of 2014, primarily due to an increase in capitalized interest (AFUDC) driven by the construction of the ReACTTM emission control technology at Weston Unit 3.

Consolidated Income Tax Expense
 
 
Three Months Ended September 30
 
 
2015
 
B (W)
 
2014
Effective tax rate
 
37.8
%
 
(0.1
)%
 
37.7
%

NINE MONTHS ENDED SEPTEMBER 30, 2015

Consolidated Earnings

The following table compares our consolidated results for the first nine months of 2015 with the first nine months of 2014, including favorable or better, "B", and unfavorable or worse, "W", variances:
 
 
Nine Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Electric utility operations
 
$
96.6

 
$
11.4

 
$
85.2

Natural gas utility operations
 
9.5

 
(8.1
)
 
17.6

Other operations
 
5.8

 
(1.0
)
 
6.8

Net income attributed to common shareholder
 
$
111.9

 
$
2.3

 
$
109.6


Electric Utility Segment Contribution to Operating Income
 
 
Nine Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Revenues
 
$
920.1

 
$
(21.1
)
 
$
941.2

Fuel and purchased power
 
333.0

 
20.3

 
353.3

Total electric margins
 
587.1

 
(0.8
)
 
587.9

 
 
 
 
 
 
 
Other operation and maintenance
 
303.0

 
18.7

 
321.7

Depreciation and amortization
 
77.5

 
(2.8
)
 
74.7

Property and revenue taxes
 
27.3

 
(0.1
)
 
27.2

Operating income
 
$
179.3

 
$
15.0

 
$
164.3


26



The following tables provide information on sales volumes by customer class and weather statistics:
 
 
Nine Months Ended September 30
 
 
MWh (in thousands)
Electric Sales Volumes
 
2015
 
B (W)
 
2014
Customer class
 
 

 
 
 
 

Residential
 
2,126.3

 
(30.4
)
 
2,156.7

Small commercial and industrial
 
3,020.8

 
54.6

 
2,966.2

Large commercial and industrial
 
3,073.1

 
59.2

 
3,013.9

Other
 
22.5

 
(0.3
)
 
22.8

Total retail
 
8,242.7

 
83.1

 
8,159.6

Wholesale – other
 
2,003.5

 
(79.3
)
 
2,082.8

Resale
 
773.7

 
340.4

 
433.3

Total sales in MWh
 
11,019.9

 
344.2

 
10,675.7


 
 
Nine Months Ended September 30
 
 
Degree Days
Weather *
 
2015

B (W)

2014
Heating (4,857 normal)
 
4,906

 
(872
)
 
5,778

Cooling (496 normal)
 
494

 
161

 
333


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

Operating Income

Operating income at the electric utility segment increased $15.0 million, driven by:

A $19.1 million decrease in maintenance expense, primarily due to planned outages at Pulliam Unit 8 and the Weston units in 2014. Maintenance expense also decreased at our jointly-owned plants in 2015.

A $9.2 million increase in electric margins resulting from over-collections of actual fuel and purchased power costs as compared with costs approved in rates in 2015, as opposed to under-collections of actual costs as compared with costs approved in 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, and the remaining variance impacts margins.

A $3.3 million decrease in operating expenses related to asset usage charges from WBS.

These increases in operating income were partially offset by:

A $7.5 million decrease from electric margins 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 the higher cost of fuel for electric generation, which does not impact margins unless costs differ less than 2% from the amounts included in rates, as discussed above. See Note 11, Regulatory Environment, for more information.

A $6.3 million increase in electric transmission expenses from MISO and ATC. This increase was partially driven by higher costs to meet ATC's revenue requirements as well as increased costs from MISO related to transmission providers' continued investment in equipment and facilities for improved reliability. Transmission expenses in 2015 have been lowered to amounts included in 2015 rates due to the PSCW's approval of escrow treatment starting in 2015.

A $2.8 million increase in depreciation and amortization expense, primarily due to the installation of scrubbers at the Columbia plant in April 2014.


27


Natural Gas Utility Segment Contribution to Operating Income
 
 
Nine Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Revenues
 
$
234.4

 
$
(120.8
)
 
$
355.2

Cost of natural gas sold
 
141.7

 
109.7

 
251.4

Total natural gas margins
 
92.7

 
(11.1
)
 
103.8

 
 
 
 
 
 
 
Other operation and maintenance
 
53.4

 
(0.9
)
 
52.5

Depreciation and amortization
 
12.7

 
(0.5
)
 
12.2

Property and revenue taxes
 
3.3

 
(0.9
)
 
2.4

Operating income
 
$
23.3

 
$
(13.4
)
 
$
36.7


The following tables provide information on sales volumes by customer class and weather statistics:
 
 
Nine Months Ended September 30
 
 
Therms (in millions)
Natural Gas Sales Volumes
 
2015
 
B (W)
 
2014
Customer Class
 
 

 
 
 
 

Residential
 
174.8

 
(22.3
)
 
197.1

Commercial and industrial
 
117.7

 
(16.4
)
 
134.1

Other
 
19.9

 
6.1

 
13.8

Total retail
 
312.4

 
(32.6
)
 
345.0

Transport
 
268.2

 
(2.2
)
 
270.4

Total sales in therms
 
580.6

 
(34.8
)
 
615.4


 
 
Nine Months Ended September 30
 
 
Degree Days
Weather *
 
2015
 
B (W)
 
2014
Heating (normal 4,857)
 
4,906

 
(872
)
 
5,778


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

Operating Income

Operating income at the natural gas utility segment decreased $13.4 million, driven by:

A $7.3 million decrease in natural gas margins related to sales volume variances, primarily due to warmer weather in 2015.

A $4.0 million decrease in natural gas margins related to the PSCW rate order, effective January 1, 2015. Although the PSCW approved a much larger rate decrease in 2015, the majority of the decrease related to decoupling refunds to customers, which has no impact on margins. See Note 11, Regulatory Environment, for more information.

A $3.4 million increase in individually non-significant operating expenses, which include administrative and general salaries, property and revenue taxes, maintenance, and depreciation and amortization.

These decreases in operating income were partially offset by $1.8 million of lower individually non-significant operating expenses, which include costs for energy efficiency programs as well as asset usage charges from WBS.

Other Segment Operations
 
 
Nine Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Operating income
 
$

 
$
(0.4
)
 
$
0.4



28


Consolidated Other Income, Net
 
 
Nine Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
AFUDC - Equity
 
$
10.4

 
$
1.9

 
$
8.5

Equity in earnings of equity method investments
 
7.6

 
(0.9
)
 
8.5

Other, net
 
1.8

 
(1.3
)
 
3.1

Other income, net
 
$
19.8

 
$
(0.3
)
 
$
20.1


Other income, net decreased by $0.3 million when compared to the first nine months of 2014. This decrease was due to lower equity earnings from WPS Investments, LLC, which holds an interest in ATC, as well as other various decreases, none of which were individually significant. These decreases were partially offset by an increase in AFUDC driven by the construction of the ReACTTM emission control technology at Weston Unit 3.

Consolidated Interest Expense
 
 
Nine Months Ended September 30
(in millions)
 
2015
 
B (W)
 
2014
Interest expense
 
$
40.3

 
$
2.6

 
$
42.9


Interest expense decreased by $2.6 million when compared to the first nine months of 2014, primarily due to a period-over-period decrease in amortization of a prior year deferral of interest expense. Also contributing to the decrease was an increase in capitalized interest driven by the construction of the ReACTTM emission control technology at Weston Unit 3.

Consolidated Income Tax Expense
 
 
Nine Months Ended September 30
 
 
2015
 
B (W)
 
2014
Effective tax rate
 
37.3
%
 
%
 
37.3
%

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.
 
Cash Flows

The following summarizes our cash flows during the nine months ended September 30:
(in millions)
 
2015
 
2014
Cash provided by (used in):
 
 
 
 
Operating activities
 
$
320.0

 
$
228.0

Investing activities
 
(269.9
)
 
(218.6
)
Financing activities
 
(52.6
)
 
(11.5
)

Operating Activities

During the nine months ended September 30, 2015, net cash provided by operating activities was $320.0 million, compared with $228.0 million during the same period in 2014. The $92.0 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 $32.2 million increase in cash related to lower payments for operating and maintenance costs in 2015. The lower payments were partially driven by a decrease in electric utility maintenance.

29



A $13.2 million increase in cash from customer prepayments and credit balances. In 2015, customer prepayments grew during the warmer winter.

A $13.0 million net increase in cash related to lower payments for natural gas, fuel, and purchased power, partially offset by a decrease in cash driven by lower overall collections from customers in 2015. This net increase was primarily due to the impact of our 2015 rate order, lower commodity prices, and the warmer winter in 2015.

An $8.1 million increase in cash received from income taxes, primarily driven by the net period-over-period change in estimated tax payments.

These increases in cash were partially offset by:

A $9.2 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 $6.5 million decrease in cash due to an increase in payments for environmental remediation activities in 2015.

Investing Activities

During the nine months ended September 30, 2015, net cash used in investing activities was $269.9 million, compared with $218.6 million during the same period in 2014. The $51.3 million increase in net cash used in investing activities was primarily due to an increase in cash used to fund capital expenditures (discussed below) in 2015.

Capital Expenditures

Capital expenditures by business segment for the nine months ended September 30 were as follows:
Reportable Segment
(in millions)
 
2015
 
2014
 
Change in 2015 Over 2014
Electric utility
 
$
230.0

 
$
182.8

 
$
47.2

Natural gas utility
 
35.6

 
33.0

 
2.6

Total capital expenditures
 
$
265.6

 
$
215.8

 
$
49.8


The increase in capital expenditures at the electric utility segment in 2015 was primarily due to the construction of the ReACTTM emission control technology at Weston Unit 3, the System Modernization and Reliability Project, and an expansion of our Legner landfill site. These increases were partially offset by lower period-over-period capital expenditures related to environmental compliance projects at the Columbia plant.

Financing Activities

During the nine months ended September 30, 2015, net cash used in financing activities was $52.6 million, compared with $11.5 million for the same period in 2014. The $41.1 million increase in cash used in financing activities was driven by an $80.4 million decrease in net borrowings of commercial paper in 2015, partially offset by a $45.0 million increase in equity contributions from 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 nine months ended September 30, 2015.


30


Capital Resources and Requirements

Working Capital

As of September 30, 2015, our current liabilities exceeded our current assets by approximately $176.1 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place for ongoing operations. We also have access to the capital markets to finance our construction program and to refinance current maturities of long-term debt, if necessary.

Liquidity

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 our existing operations primarily through internally generated funds (net of forecasted dividend payments), debt financings, and equity infusions from Integrys. 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 notes. Amounts, prices, and terms will be determined at the time of future offerings.

In October 2015, we announced the planned redemption of all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7-1/8% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption.  The scheduled date of redemption is November 13, 2015. Following this redemption, we will discharge our mortgage indenture and do not intend to issue additional first mortgage bonds under the mortgage indenture.

All $1,175.0 million of our senior notes outstanding are also secured by first mortgage bonds. On the redemption date of the 7-1/8% Series, the senior notes will become senior unsecured obligations and rank equally with all of our other unsecured and unsubordinated obligations.

In addition, on October 14, 2015, we issued notices of redemption for all 511,882 outstanding shares of our five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and, (v) 150,000 shares of 6.88% Series.  The scheduled date of redemption is November 13, 2015. The aggregate redemption price is $52.8 million, plus accumulated and unpaid dividends.

Credit Rating Risk

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.

In August 2015, Fitch Ratings, Inc. assigned ratings to us for the first time. We were assigned an F1 rating for our short-term debt and an AA- rating for our senior secured debt. Our outlook is stable. During the third quarter of 2015, there were no changes to the credit ratings issued by Moody's Investors Service and Standard & Poor's Ratings Services.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

See Liquidity and Capital Resources—Credit Ratings in Item 7 of our 2014 Annual Report on Form 10-K for additional information related to our credit rating risk.


31


Capital Requirements

In our previously filed 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 will no longer be needed at this time. See Factors Affecting Results, Liquidity and Capital Resources—Regulatory Matters for more information. In addition, all of our projected capital expenditures are being reviewed in connection with the WEC Merger.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors.

Contractual Obligations

See Future Capital Requirements and Resources—Contractual Obligations in Item 7 of our 2014 Annual Report on Form 10-K for additional information about our commitments.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information under Liquidity and Capital Resources—Other Future Considerations in Item 7 of our 2014 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting our operations.

Regulatory Matters

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

In 2013, we announced a need for an additional 400 to 500 MWs of electric generating capacity by 2019 to meet the energy needs of our customers. After evaluating various options, we proposed building a new 400 MW 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. In September 2015, we, along with Wisconsin Electric, filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time.

See Liquidity and Capital Resources—Other Future Considerations in Item 7 of our 2014 Annual Report on Form 10-K for additional information.

Electric Transmission and Energy Markets

Presque Isle System Support Resource Costs

In August 2013, Wisconsin Electric 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 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 initially planned to compensate Wisconsin Electric 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 February 2015, Wisconsin Electric 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.


32


In May 2015, MISO made a compliance filing regarding the allocation of Presque Isle SSR costs incurred while the SSR was in effect, which did not allocate any of these SSR costs to us. In September 2015, the FERC approved MISO's new cost allocation method. Subsequently, several parties have sought rehearing of this FERC order.

A potential reallocation of the Presque Isle SSR costs based on the rehearing requests may result in a change in SSR costs allocated to us. If any SSR costs are allocated to us, costs related to retail customers will be deferred based on an order from the PSCW. We expect the PSCW to determine the appropriate ratemaking treatment after December 31, 2015. We expect that costs for our Michigan customers would be recovered through the Power Supply Cost Recovery mechanism, and costs for our wholesale customers would be recovered through formula rates.

ATC Allowed ROE Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base 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. The FERC conducted hearings in August 2015, and an initial decision is expected by November 30, 2015. 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 expects to conduct hearings in January 2016 with respect to the second complaint, and an initial decision is expected by June 30, 2016.

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. The FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. 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 distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. In the first quarter of 2015, ATC recorded a reserve for anticipated refunds to customers related to this complaint, which has reduced our equity earnings from ATC.

See Liquidity and Capital Resources—Other Future Considerations in Item 7 of our 2014 Annual Report on Form 10-K, for additional information.


33


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2014. In addition to the Form 10-K disclosures, see Note 9, Derivative Instruments, and
Note 10, Fair Value Measurements, in this report for information concerning our market risk exposures.


34


ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have 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 Exchange Act, and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15[f] and 15d-15[f]) during the fiscal quarter to which this report relates that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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


35


PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2014 Annual Report on Form 10-K and Note 6, Commitments and Contingencies, in this report.

In addition to those legal proceedings discussed in our reports to the SEC, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

ITEM 1A. RISK FACTORS

Other than the inapplicability of the Risk Related to the Proposed Merger of Integrys with Wisconsin Energy Corporation (Wisconsin Energy), which has been replaced by the risks set forth below, there were no material changes in the risk factors presented in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2014.

Risks Related to the WEC Merger

The WEC Merger may not achieve its anticipated results, and WEC Energy Group may be unable to integrate our operations as expected.
 
The 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 WEC Energy Group and Integrys 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 the combined company's ability to achieve the anticipated benefits of the transaction as and when expected. WEC Energy Group and Integrys 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 WEC Merger may adversely affect our ability to attract and retain key employees.

Current and prospective employees may experience uncertainty about their future roles with us as a result of the transaction. 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.


36


ITEM 6. EXHIBITS
Exhibit No.
 
Description
12
 
Statements Regarding Computation of Ratios
 
 
 
12.1
 
Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements
 
 
 
31
 
Rule 13a-14(a) / 15d-14(a) Certifications
 
 
 
31.1
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation.
 
 
 
31.2
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation.
 
 
 
32
 
Section 1350 Certifications
 
 
 
32.1
 
Written Statement of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation.
 
 
 
32.2
 
Written Statement of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation.
 
 
 
101
 
Interactive Data File


37


SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
 
WISCONSIN PUBLIC SERVICE CORPORATION
 
 
(Registrant)
 
 
 
Date:
November 6, 2015
/s/ William J. Guc
 
 
William J. Guc
 
 
Vice President and Controller
 
 
 
 
 
(Duly Authorized Officer and Chief Accounting Officer)


38