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EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO /WI/nspwex3101q22014.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO /WI/nspwex3102q22014.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO /WI/nspwex9901q22014.htm

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2014
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-03140
Northern States Power Company
(Exact name of registrant as specified in its charter)
Wisconsin
 
39-0508315
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
1414 West Hamilton Avenue
 
 
Eau Claire, Wisconsin
 
54701
(Address of principal executive offices)
 
(Zip Code)
(715) 737-2625
(Registrant’s telephone number, including area code)

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.  x Yes  ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes  ¨ 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 ¨
(Do not check if 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  x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
 
Outstanding at Aug. 4, 2014
Common Stock, $100 par value
 
933,000 shares
Northern States Power Company (a Wisconsin corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.
 
 
 
 
 



TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
 
 
 
 
Item l    
Item 2   
Item 4   
 
 
 
PART II — OTHER INFORMATION
 
 
 
 
Item 1    
Item 1A
Item 4    
Item 5    
Item 6    
 
 
 
Certifications Pursuant to Section 302
1

Certifications Pursuant to Section 906
1

Statement Pursuant to Private Litigation
1


This Form 10-Q is filed by Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin).  NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Southwestern Public Service Company, a New Mexico corporation (SPS); Public Service Company of Colorado, a Colorado corporation (PSCo); and NSP-Wisconsin.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).



2


PART I — FINANCIAL INFORMATION
Item 1 — FINANCIAL STATEMENTS

NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands)
 
Three Months Ended June 30
 
Six Months Ended June 30
 
2014
 
2013
 
2014
 
2013
Operating revenues
 
 
 
 
 
 
 
Electric
$
198,277

 
$
185,374

 
$
409,374

 
$
376,185

Natural gas
29,539

 
24,555

 
103,330

 
74,912

Other
298

 
246

 
552

 
493

Total operating revenues
228,114

 
210,175

 
513,256

 
451,590

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Electric fuel and purchased power, non-affiliates
2,684

 
1,862

 
9,180

 
6,032

Purchased power, affiliates
104,532

 
100,043

 
216,458

 
198,985

Cost of natural gas sold and transported
19,194

 
14,302

 
70,336

 
45,287

Operating and maintenance expenses
48,433

 
42,992

 
92,664

 
84,668

Conservation program expenses
3,015

 
3,118

 
5,687

 
6,110

Depreciation and amortization
19,874

 
19,051

 
39,181

 
37,906

Taxes (other than income taxes)
6,652

 
6,341

 
13,449

 
12,735

Total operating expenses
204,384

 
187,709

 
446,955

 
391,723

 
 
 
 
 
 
 
 
Operating income
23,730

 
22,466

 
66,301

 
59,867

 
 
 
 
 
 
 
 
Other (expense) income, net
(70
)
 
155

 
54

 
270

Allowance for funds used during construction — equity
1,767

 
780

 
3,339

 
1,726

 
 
 
 
 
 
 
 
Interest charges and financing costs
 

 
 

 
 

 
 

Interest charges — includes other financing costs of
$377, $380, $751 and $761, respectively
6,968

 
6,814

 
13,835

 
13,669

Allowance for funds used during construction — debt
(850
)
 
(400
)
 
(1,608
)
 
(809
)
Total interest charges and financing costs
6,118

 
6,414

 
12,227

 
12,860

 
 
 
 
 
 
 
 
Income before income taxes
19,309

 
16,987

 
57,467

 
49,003

Income taxes
7,287

 
6,443

 
21,210

 
18,774

Net income
$
12,022

 
$
10,544

 
$
36,257

 
$
30,229


See Notes to Consolidated Financial Statements


3


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)
 
Three Months Ended June 30
 
Six Months Ended June 30
 
2014
 
2013
 
2014
 
2013
Net income
$
12,022

 
$
10,544

 
$
36,257

 
$
30,229

Other comprehensive income
 

 
 

 
 
 
 
Derivative instruments:
 

 
 

 
 
 
 
Reclassification of losses to net income, net of tax of $12, $14, $25 and $26, respectively
19

 
18

 
37

 
37

Other comprehensive income
19

 
18

 
37

 
37

Comprehensive income
$
12,041

 
$
10,562

 
$
36,294

 
$
30,266


See Notes to Consolidated Financial Statements


4


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Six Months Ended June 30
 
2014
 
2013
Operating activities
 
 
 
Net income
$
36,257

 
$
30,229

Adjustments to reconcile net income to cash provided by operating activities:
 

 
 

Depreciation and amortization
39,754

 
38,476

Deferred income taxes
16,877

 
15,407

Amortization of investment tax credits
(337
)
 
(332
)
Allowance for equity funds used during construction
(3,339
)
 
(1,726
)
Net derivative losses (gains)
108

 
(344
)
Changes in operating assets and liabilities:
 

 
 

Accounts receivable
2,105

 
1,134

Accrued unbilled revenues
10,460

 
9,928

Inventories
2,672

 
1,913

Other current assets
3,680

 
3,442

Accounts payable
(3,981
)
 
(5,435
)
Net regulatory assets and liabilities
(23,547
)
 
(806
)
Other current liabilities
(22
)
 
1,670

Pension and other employee benefit obligations
(7,378
)
 
(10,234
)
Change in other noncurrent assets
101

 
329

Change in other noncurrent liabilities
872

 
630

Net cash provided by operating activities
74,282

 
84,281

 
 
 
 
Investing activities
 

 
 

Utility capital/construction expenditures
(124,624
)
 
(81,603
)
Allowance for equity funds used during construction
3,339

 
1,726

Other, net
8

 
(230
)
Net cash used in investing activities
(121,277
)
 
(80,107
)
 
 
 
 
Financing activities
 

 
 

Repayments of short-term borrowings, net
(57,000
)
 
(37,000
)
Proceeds from (repayments of) notes payable to affiliate
30

 
(80
)
Proceeds from issuance of long-term debt

98,926

 

Repayments of long-term debt
(36
)
 
(92
)
Capital contributions from parent
20,479

 
45,093

Dividends paid to parent
(16,089
)
 
(15,186
)
Net cash provided by (used in) financing activities
46,310

 
(7,265
)
 
 
 
 
Net change in cash and cash equivalents
(685
)
 
(3,091
)
Cash and cash equivalents at beginning of period
1,349

 
4,459

Cash and cash equivalents at end of period
$
664

 
$
1,368

 
 
 
 
Supplemental disclosure of cash flow information:
 

 
 

Cash paid for interest (net of amounts capitalized)
$
(11,516
)
 
$
(12,122
)
Cash (paid) received for income taxes, net
(359
)
 
39

Supplemental disclosure of non-cash investing transactions:
 

 
 

Property, plant and equipment additions in accounts payable
$
16,844

 
$
9,134


See Notes to Consolidated Financial Statements

5


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)
 
June 30, 2014
 
Dec. 31, 2013
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
664

 
$
1,349

Accounts receivable, net
51,684

 
57,674

Accounts receivable from affiliates
5,480

 
1,595

Accrued unbilled revenues
41,174

 
51,634

Inventories
18,803

 
21,475

Regulatory assets
24,835

 
14,866

Prepaid taxes
24,278

 
27,518

Deferred income taxes
10,975

 
14,953

Prepayments and other
4,356

 
5,056

Total current assets
182,249

 
196,120

 
 
 
 
Property, plant and equipment, net
1,521,829

 
1,442,779

 
 
 
 
Other assets
 

 
 

Regulatory assets
252,169

 
233,193

Other investments
3,643

 
3,650

Other
4,164

 
3,651

Total other assets
259,976

 
240,494

Total assets
$
1,964,054

 
$
1,879,393

 
 
 
 
Liabilities and Equity
 

 
 

Current liabilities
 

 
 

Current portion of long-term debt
$
1,207

 
$
107

Short-term debt
11,000

 
68,000

Notes payable to affiliates
500

 
470

Accounts payable
34,353

 
52,086

Accounts payable to affiliates
28,360

 
24,986

Dividends payable to parent
16,243

 
8,032

Regulatory liabilities
4,047

 
9,717

Taxes accrued
5,539

 
5,638

Environmental liabilities
34,380

 
28,785

Accrued interest
7,593

 
7,507

Other
8,341

 
9,376

Total current liabilities
151,563

 
214,704

 
 
 
 
Deferred credits and other liabilities
 

 
 

Deferred income taxes
320,334

 
305,139

Deferred investment tax credits
9,361

 
9,698

Regulatory liabilities
134,492

 
126,424

Environmental liabilities
80,109

 
79,703

Customer advances
16,678

 
16,008

Pension and employee benefit obligations
38,330

 
45,708

Other
9,362

 
9,237

Total deferred credits and other liabilities
608,666

 
591,917

 
 
 
 
Commitments and contingencies


 


Capitalization
 

 
 

Long-term debt
567,070

 
468,490

Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares
outstanding at June 30, 2014 and Dec. 31, 2013, respectively
93,300

 
93,300

Additional paid in capital
269,322

 
248,844

Retained earnings
274,457

 
262,499

Accumulated other comprehensive loss
(324
)
 
(361
)
Total common stockholder’s equity
636,755

 
604,282

Total liabilities and equity
$
1,964,054

 
$
1,879,393


See Notes to Consolidated Financial Statements

6


NSP-WISCONSIN AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Wisconsin and its subsidiaries as of June 30, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2014 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2013. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2013, filed with the SEC on Feb. 24, 2014. Due to the seasonality of NSP-Wisconsin’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1.
Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Issued

Revenue Recognition - In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
56,469

 
$
62,585

Less allowance for bad debts
 
(4,785
)
 
(4,911
)
 
 
$
51,684

 
$
57,674


(Thousands of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Inventories
 
 
 
 
Materials and supplies
 
$
6,882

 
$
6,437

Fuel
 
7,071

 
5,915

Natural gas
 
4,850

 
9,123

 
 
$
18,803

 
$
21,475


7


(Thousands of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
1,984,497

 
$
1,913,354

Natural gas plant
 
239,659

 
236,047

Common and other property
 
114,063

 
112,886

Construction work in progress
 
154,992

 
127,954

Total property, plant and equipment
 
2,493,211

 
2,390,241

Less accumulated depreciation
 
(971,382
)
 
(947,462
)
 
 
$
1,521,829

 
$
1,442,779


4.
Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2014, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the first quarter of 2014, the state of Wisconsin completed an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of June 30, 2014, there were no state income tax audits in progress.

Unrecognized Tax Benefits The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions
 
$
0.1

 
$
0.1

Unrecognized tax benefit — Temporary tax positions
 
1.7

 
1.4

Total unrecognized tax benefit
 
$
1.8

 
$
1.5


The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
NOL and tax credit carryforwards
 
$
(0.4
)
 
$
(0.4
)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.


8


The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2014 or Dec. 31, 2013.

5.
Rate Matters

Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)

NSP-Wisconsin 2015 Electric Rate Case — In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request is for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes are being requested to the capital structure or the 10.2 percent return on equity (ROE) authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers.

The major cost components of the requested increase are summarized below:
(Millions of Dollars)
 
Request
Production and transmission fixed charges
 
$
28.1

Fuel and purchased power
 
13.9

Sub-Total
 
$
42.0

 
 
 
NSP-Minnesota transmission depreciation reserve
 
$
(16.2
)
Monticello extended power uprate deferral
 
(5.2
)
Total
 
$
20.6


The next steps in the procedural schedule are expected to be as follows:
Direct Testimony (PSCW staff and intervenors) — Oct. 3, 2014;
Rebuttal Testimony — Oct. 17, 2014;
Surrebuttal Testimony — Oct. 24, 2014; and
Evidentiary Hearing — Oct. 28, 2014;

A final PSCW decision is anticipated by the end of the year with final rates implemented in January 2015.

Recently Concluded Regulatory Proceedings — Michigan Public Service Commission (MPSC)

Michigan 2014 Natural Gas Rate Case — In December 2013, NSP-Wisconsin filed a request with the MPSC to increase rates for natural gas distribution service by $527,000, or 8.8 percent and implement a gas meter pressure correction factor. The filing was based on a 2014 forecast test year, a ROE of 10.4 percent, an equity ratio of 52.54 percent and a forecasted average rate base of approximately $4.7 million. The MPSC staff was the only other party to the proceeding.

In May 2014, the MPSC issued an order approving the settlement agreement reached by NSP-Wisconsin and the MPSC staff, authorizing an increase of $500,000 or 8.4 percent, based on a 10.2 percent ROE and accepting the proposed gas meter pressure correction factor. Under the terms of the settlement agreement, the rate increase will be phased in over two years, with phase one rates effective July 1, 2014 and phase two rates effective July 1, 2015.


9


Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

MISO ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

In January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO transmission owners’ motion to dismiss. The complaint is pending FERC action.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC set the issue of the appropriate long-term growth rate for further hearing procedures. The FERC could order settlement judge procedures, and if necessary a hearing, to apply the new methodology to MISO transmission owners. The new FERC ROE methodology is expected to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Wisconsin’s financial position.

Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program. NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement. The guarantee issued by NSP-Wisconsin limits their exposure to a maximum amount stated in the guarantee. The guarantee contains no recourse provisions and requires no collateral.

The following table presents the guarantee issued and outstanding for NSP-Wisconsin:
(Millions of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Guarantees issued and outstanding
 
$
1.0

 
$
1.0

Current exposure under these guarantees
 
0.2

 
0.3


Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.


10


In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.

In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. The settlement reflects a cost estimate for the cleanup of the Phase I Project Area of $40 million. Demolition activities occurred at the Ashland site in 2013. The final design for the soil, including excavation and treatment, as well as containment wall remedies was submitted to the EPA in April 2014 and work commenced in May 2014. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and those activities are expected to commence in 2015. Based on these updated designs, the updated cost estimate for the cleanup of the Phase I Project Area is approximately $52 million, of which $12 million has already been spent. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA. Implementation of the pilot is anticipated in late summer or early fall of 2014.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At June 30, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $113.3 million and $104.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $33.4 million and $25.2 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process. Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.


11


In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize these estimated costs over a ten-year period; and (3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area. The PSCW determined the timing of the cleanup of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the cleanup in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

Environmental Requirements

Water and waste
Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. NSP-Wisconsin estimates the most likely cost for compliance is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

Air
EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. NSP-Wisconsin is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Wisconsin’s power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Wisconsin operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.


12


GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards are not based on and would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at NSP-Wisconsin’s power plants.

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO2) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Wisconsin. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule. The rule would also create an emissions trading program.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit has not yet ruled on the motion to lift the stay. Because it is not yet known how the litigation over the remaining issues will be resolved or how the D.C. Circuit will rule on the motion to lift the stay, it is not yet known what requirements may be imposed in the future, or their timing.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, NSP-Wisconsin expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At June 30, 2014, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.

Legal Contingencies

NSP-Wisconsin is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Wisconsin’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.


13


7.
Borrowings and Other Financing Instruments

Commercial Paper — NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Wisconsin was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended June 30, 2014
 
Twelve Months Ended Dec. 31, 2013
Borrowing limit
 
$
150

 
$
150

Amount outstanding at period end
 
11

 
68

Average amount outstanding
 
72

 
20

Maximum amount outstanding
 
101

 
71

Weighted average interest rate, computed on a daily basis
 
0.25
%
 
0.31
%
Weighted average interest rate at period end
 
0.24

 
0.27


Letters of Credit — NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2014 and Dec. 31, 2013, there were no letters of credit outstanding.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At June 30, 2014, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):
Credit Facility (a)
 
Drawn (b)
 
Available
$
150.0

 
$
11.0

 
$
139.0


(a) 
Credit facility expires in July 2017.
(b) 
Includes outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at June 30, 2014 and Dec. 31, 2013.

Other Short-Term Borrowings The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.:
(Amounts in Millions, Except Interest Rates)
 
June 30, 2014
 
Dec. 31, 2013
Notes payable to affiliates
 
$
0.5

 
$
0.5

Weighted average interest rate at period end
 
0.43
%
 
0.24
%

Long-Term Borrowings

In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.
 
8.
Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value.  A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.


14


Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Interest rate derivatives The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Derivative Instruments Fair Value Measurements

NSP-Wisconsin enters into derivative instruments, including forward contracts, futures, swaps and options, to manage risk in connection with changes in interest rates and utility commodity prices.

Interest Rate Derivatives — NSP-Wisconsin enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At June 30, 2014, accumulated other comprehensive loss related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Commodity Derivatives — NSP-Wisconsin may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale.

The following table details the gross notional amounts of commodity options at June 30, 2014 and Dec. 31, 2013:
(Amounts in Thousands) (a)(b)
 
June 30, 2014
 
Dec. 31, 2013
Million British thermal units of natural gas
 
448

 
987


(a) 
Amounts are not reflective of net positions in the underlying commodities.
(b) 
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended June 30, 2014 and 2013, and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the six months ended June 30, 2014 and 2013.

During the three months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses recognized as regulatory assets and liabilities.  For the three months ended June 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities.  During the six months ended June 30, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.7 million, recognized as regulatory assets and liabilities. During the six months ended June 30, 2013, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement gains of $0.5 million were recognized for the six months ended June 30, 2014, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate. There were immaterial natural gas commodity derivatives settlement losses recognized during the three months ended June 30, 2014, and three and six months ended June 30, 2013.


15


NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations  NSP-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment, as well as an assessment of the impact of NSP-Wisconsin’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

NSP-Wisconsin employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and Dec. 31, 2013:
 
 
June 30, 2014
 
 
Fair Value
 
 
 
 
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Fair Value
Total
 
Counterparty
Netting (a)
 
Total (b)
Current derivative assets
 
 

 
 

 
 

 
 

 
 

 
 

Natural gas commodity
 
$

 
$
321

 
$

 
$
321

 
$

 
$
321

 
 
Dec. 31, 2013
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
Total (b)
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$

 
$
580

 
$

 
$
580

 
$

 
$
580


(a) 
NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2014 and Dec. 31, 2013.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b) 
Included in prepayments and other assets balance of $4.4 million and $5.1 million at June 30, 2014 and Dec. 31, 2013, respectively, in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
 
June 30, 2014
 
Dec. 31, 2013
(Thousands of Dollars)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt, including current portion
 
$
568,277

 
$
652,505

 
$
468,597

 
$
518,269


The fair value of NSP-Wisconsin’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of June 30, 2014 and Dec. 31, 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


16


9.
Other (Expense) Income, Net

Other (expense) income, net consisted of the following:
 
 
Three Months Ended June 30
 
Six Months Ended June 30
(Thousands of Dollars)
 
2014
 
2013
 
2014
 
2013
Interest income
 
$
12

 
$
197

 
$
216

 
$
396

Other nonoperating income
 
44

 
29

 
79

 
70

Insurance policy expense
 
(124
)
 
(69
)
 
(236
)
 
(191
)
Other nonoperating expense
 
(2
)
 
(2
)
 
(5
)
 
(5
)
Other (expense) income, net
 
$
(70
)
 
$
155

 
$
54

 
$
270


10.
Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker.  NSP-Wisconsin evaluates performance based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

NSP-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

NSP-Wisconsin’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Wisconsin and Michigan. 
NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas primarily in portions of Wisconsin and Michigan.
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include investments in rental housing projects that qualify for low-income housing tax credits.

Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
(Thousands of Dollars)
 
Regulated Electric
 
Regulated Natural Gas
 
All Other
 
Reconciling Eliminations
 
Consolidated Total
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
198,277

 
$
29,539

 
$
298

 
$

 
$
228,114

Intersegment revenues
 
123

 
849

 

 
(972
)
 

Total revenues
 
$
198,400

 
$
30,388

 
$
298

 
$
(972
)
 
$
228,114

Net income (loss)
 
$
11,799

 
$
(141
)
 
$
364

 
$

 
$
12,022

(Thousands of Dollars)
 
Regulated Electric
 
Regulated Natural Gas
 
All Other
 
Reconciling Eliminations
 
Consolidated Total
Three Months Ended June 30, 2013
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
185,374

 
$
24,555

 
$
246

 
$

 
$
210,175

Intersegment revenues
 
83

 
278

 

 
(361
)
 

Total revenues
 
$
185,457

 
$
24,833

 
$
246

 
$
(361
)
 
$
210,175

Net income
 
$
10,068

 
$
201

 
$
275

 
$

 
$
10,544

(a) 
Operating revenues include $33 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013.

17


(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All
Other
 
Reconciling
Eliminations
 
Consolidated
Total
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
409,374

 
$
103,330

 
$
552

 
$

 
$
513,256

Intersegment revenues
 
215

 
3,766

 

 
(3,981
)
 

Total revenues
 
$
409,589

 
$
107,096

 
$
552

 
$
(3,981
)
 
$
513,256

Net income
 
$
26,865

 
$
7,568

 
$
1,824

 
$

 
$
36,257

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All
Other
 
Reconciling
Eliminations
 
Consolidated
Total
Six Months Ended June 30, 2013
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
376,185

 
$
74,912

 
$
493

 
$

 
$
451,590

Intersegment revenues
 
161

 
586

 

 
(747
)
 

Total revenues
 
$
376,346

 
$
75,498

 
$
493

 
$
(747
)
 
$
451,590

Net income
 
$
23,671

 
$
5,825

 
$
733

 
$

 
$
30,229

(a) 
Operating revenues include $63 million and $65 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

11.
Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost
 
 
Three Months Ended June 30
 
 
2014
 
2013
 
2014
 
2013
(Thousands of Dollars)
 
Pension Benefits
 
Postretirement Health
Care Benefits
Service cost
 
$
1,132

 
$
1,420

 
$
8

 
$
6

Interest cost
 
1,814

 
1,731

 
197

 
190

Expected return on plan assets
 
(2,410
)
 
(2,498
)
 
(13
)
 
(10
)
Amortization of prior service cost (credit)
 
28

 
104

 
(87
)
 
(88
)
Amortization of net loss
 
1,654

 
1,981

 
166

 
241

Net benefit cost recognized for financial reporting
 
$
2,218

 
$
2,738

 
$
271

 
$
339

 
 
Six Months Ended June 30
 
 
2014
 
2013
 
2014
 
2013
(Thousands of Dollars)
 
Pension Benefits
 
Postretirement Health
Care Benefits
Service cost
 
$
2,264

 
$
2,841

 
$
17

 
$
12

Interest cost
 
3,628

 
3,462

 
395

 
380

Expected return on plan assets
 
(4,821
)
 
(4,997
)
 
(26
)
 
(21
)
Amortization of prior service cost (credit)
 
56

 
208

 
(175
)
 
(176
)
Amortization of net loss
 
3,308

 
3,962

 
333

 
482

Net benefit cost recognized for financial reporting
 
$
4,435

 
$
5,476

 
$
544

 
$
677


In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $8.0 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2014.


18


12.
Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2014 and 2013 were as follows:
 
 
Gains and Losses on
Cash Flow Hedges
(Thousands of Dollars)
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1
 
$
(343
)
 
$
(418
)
Losses reclassified from net accumulated other comprehensive loss
 
19

 
18

Net current period other comprehensive income
 
19

 
18

Accumulated other comprehensive loss at June 30
 
$
(324
)
 
$
(400
)
 
 
Gains and Losses on
Cash Flow Hedges
(Thousands of Dollars)
 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1
 
$
(361
)
 
$
(437
)
Losses reclassified from net accumulated other comprehensive loss
 
37

 
37

Net current period other comprehensive income
 
37

 
37

Accumulated other comprehensive loss at June 30
 
$
(324
)
 
$
(400
)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:
 
 
Amounts Reclassified from
Accumulated Other
Comprehensive Loss
 
(Thousands of Dollars)
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
31

(a) 
$
32

(a) 
Total, pre-tax
 
31

 
32

 
Tax benefit
 
(12
)
 
(14
)
 
Total amounts reclassified, net of tax
 
$
19

 
$
18

 
 
 
Amounts Reclassified from
Accumulated Other
Comprehensive Loss
 
(Thousands of Dollars)
 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
62

(a) 
$
63

(a) 
Total, pre-tax
 
62

 
63

 
Tax benefit
 
(25
)
 
(26
)
 
Total amounts reclassified, net of tax
 
$
37

 
$
37

 

(a) 
Included in interest charges.

Item 2MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for NSP-Wisconsin is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).


19


Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of NSP-Wisconsin’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Wisconsin and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Wisconsin has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Wisconsin and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the Nuclear Regulatory Commission (NRC); financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

Results of Operations

NSP-Wisconsin’s net income was $36.3 million for the six months ended June 30, 2014 compared with $30.2 million for the same period in 2013. Higher electric and natural gas margins, due to an electric rate increase effective in January 2014, and weather-normalized sales growth (which is adjusted against a 30-year average of actual historical weather conditions) were partially offset by higher O&M expenses.

Electric Revenues and Margin

Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The electric fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings. The following table details the electric revenues and margin:
 
 
Six Months Ended June 30
(Millions of Dollars)
 
2014
 
2013
Electric revenues
 
$
409

 
$
376

Electric fuel and purchased power
 
(226
)
 
(205
)
Electric margin
 
$
183

 
$
171



20


The following tables summarize the components of the changes in electric revenues and electric margin for the six months ended June 30:

Electric Revenues
(Millions of Dollars)
 
2014 vs. 2013
Retail rate increase (Wisconsin)
 
$
12

Interchange agreement billings with NSP-Minnesota
 
8

Estimated impact of weather
 
5

Fuel and purchased power cost recovery
 
5

Retail sales growth (excluding weather impact)
 
3

Total increase in electric revenues
 
$
33


Electric Margin
(Millions of Dollars)
 
2014 vs. 2013
Retail rate increase (Wisconsin)
 
$
12

Estimated impact of weather
 
5

Retail sales growth (excluding weather impact)
 
3

Interchange agreement billings with NSP-Minnesota
 
(9
)
Other, net
 
1

Total increase in electric margin
 
$
12


Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details the natural gas revenues and margin:
 
 
Six Months Ended June 30
(Millions of Dollars)
 
2014
 
2013
Natural gas revenues
 
$
103

 
$
75

Cost of natural gas sold and transported
 
(70
)
 
(45
)
Natural gas margin
 
$
33

 
$
30


The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the six months ended June 30:

Natural Gas Revenues
(Millions of Dollars)
 
2014 vs. 2013
Purchased natural gas adjustment clause recovery
 
$
25

Estimated impact of weather
 
2

Other, net
 
1

Total increase in natural gas revenues
 
$
28


Natural Gas Margin
(Millions of Dollars)
 
2014 vs. 2013
Estimated impact of weather
 
$
2

Other, net
 
1

Total increase in natural gas margin
 
$
3



21


Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $8.0 million, or 9.4 percent, for the six months ended June 30, 2014. The following table summarizes the changes in O&M expenses:
(Millions of Dollars)
 
2014 vs. 2013
Interchange agreement billings with NSP-Minnesota
 
$
5

Electric and gas distribution expenses
 
1

Other, net
 
2

Total increase in O&M expenses
 
$
8


Allowance for funds used during construction, Equity and Debt (AFUDC) — AFUDC increased $2.4 million for the six months ended June 30, 2014. The increase was primarily due to the expansion of transmission facilities.

Income Taxes Income tax expense increased $2.4 million for the six months ended June 30, 2014. The increase in income tax expense was primarily due to higher pretax earnings in 2014. This was partially offset by increased permanent plant-related adjustments in 2014. The ETR was 36.9 percent for the six months ended June 30, 2014 compared with 38.3 percent for the same period in 2013. The lower ETR for 2014 was primarily due to increased permanent plant-related adjustments.

Public Utility Regulation

NSP System Resource Plans — In March 2013, the Minnesota Public Utilities Commission (MPUC) approved NSP-Minnesota’s Resource Plan and ordered a competitive acquisition process with the goal of adding approximately 500 megawatt (MW) of generation to the NSP System by 2019.

In May 2014, the MPUC issued its order directing NSP-Minnesota to negotiate a 100 MW solar PPA with Geronimo Energy, a natural gas, combined-cycle PPA with Calpine, a natural gas, combustion turbine PPA with Invenergy and to file these agreements later this fall. The MPUC also directed NSP-Minnesota to present its final pricing terms for its 215 MW natural gas combustion turbine, self-build option at the Black Dog site. The MPUC is expected to rule on the four options later this year.

In early 2013, NSP-Minnesota also issued a request for proposal (RFP) for wind generation and subsequently sought commission approval of the following four wind projects:
A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota;
A 150 MW ownership project for the Border Winds wind farm in North Dakota;
A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and
A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.

In October 2013, the MPUC approved the four wind projects. In 2014, the North Dakota Public Service Commission approved the prudence of the Border Winds project as part of the rate case settlement and determined it will address the Pleasant Valley project at a later date. In June and July of 2014, NSP-Minnesota finalized agreements with Renewable Energy Systems Americas, Inc. for the Pleasant Valley and Border Winds projects and anticipates both projects going into service in 2015.

In April 2014, NSP-Minnesota issued a RFP for up to 100 MWs of solar generation resources. Proposals were received in June 2014. NSP-Minnesota is evaluating such bids and plans to submit recommendations regarding selected bids with the MPUC in October 2014.

NSP-Wisconsin CapX2020 Certificate of Public Convenience and Necessity (CPCN) The PSCW issued a CPCN for the Wisconsin portion of the Hampton, Minn. to La Crosse, Wis. project in May 2012. The Wisconsin route is approximately 50 miles of new transmission line with an estimated cost of $211 million. Construction on the Wisconsin terminus of the line, the Briggs Road Substation, began in mid-2013 and construction on the Wisconsin portion of the line began in June 2014. The line is expected to go into service in 2015.


22


NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line  In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 kilovolt transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, known as the Badger Coulee line, would run between 159 and 182 miles. Updated information was provided to the PSCW in April 2014 showing an estimated project cost, including allowance for funds used during construction, of between $540 and $580 million, depending upon the route ultimately approved by the PSCW. NSP-Wisconsin’s share of the investment is estimated to be between $190 and $207 million. The cost estimates are based on a projected 2018 in-service year. In December 2011, MISO determined the line to be a multi-value project (MVP) project, and as such, eligible for cost sharing under MISO’s MVP tariff.

On April 30, 2014, the PSCW determined the CPCN application was complete. The next step is an extensive regulatory review by the PSCW, the Wisconsin Department of Natural Resources and the Department of Agriculture. By statute, the PSCW has 360 days from the determination of completeness to issue a decision on the project. If approved, NSP-Wisconsin and ATC anticipate beginning construction on the line in mid-2016, with completion by late-2018.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Wisconsin, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Wisconsin’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2013. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area.

The removal of a federal ROFR would eliminate rights that NSP-Wisconsin has under the MISO tariffs to build certain transmission projects within its footprint. In Order 1000, FERC instead required that the opportunity to build such projects would extend to competitive transmission developers. MISO made their initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. Various parties appealed Order 1000 final rules to the D.C. Circuit. The date for a Court decision in the appeal is uncertain.

The FERC ruled on the initial regional compliance filings for MISO, directing further compliance changes. The FERC ruling prohibits ROFR provisions in the MISO tariff and Transmission Owners Agreement (TOA), except for consideration of state statutes. The MISO Transmission Owners filed an appeal of this decision. Initial filings to address interregional planning and cost allocation requirements with other regions were made by MISO and are pending action by the FERC.

Minnesota, North Dakota and South Dakota legislation preserves ROFR rights. Wisconsin has not developed such legislation. The FERC’s initial order on MISO’s compliance filing required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. Xcel Energy requested rehearing of this issue. The FERC has also accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability. MISO has proposed that the Order 1000 compliance tariffs be effective for projects approved in December 2014.

23



MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving. Certain parties appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit). In June 2013, the Seventh Circuit upheld the FERC MVP tariff orders allocating MVP project costs regionally, but remanded the FERC decision to not apply the regional charge to transmission service transactions crossing into the PJM Interconnection, LLC (PJM) RTO. U.S. Supreme Court review of the Seventh Circuit decision was requested. In March 2014, the U.S. Supreme Court denied the appeal. Appeals of the regional allocation issue have thus been exhausted. The FERC has not yet taken action on the remand of the PJM allocation issue. The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery. Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities. The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation could be significant in future periods.

NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. NSP-Wisconsin is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In July 2014, the FERC issued a notice of proposed rulemaking (NOPR) generally proposing to adopt NERC’s proposed CIP standard related to physical security for bulk electric system facilities. However, the FERC proposed a modification to the standard that would allow certain governmental authorities, including FERC, to revise an entity’s list of critical facilities. The new standard would likely be effective in 2015. NSP-Wisconsin is currently in the process of evaluating and identifying the critical facilities impacted to better determine the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

Southwest Power Pool, Inc. (SPP) and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) SPP and MISO have a longstanding dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagree over MISO’s authority to transmit power over SPP transmission facilities between the traditional MISO region in the Midwest and the Entergy system. Several cases have been filed with the FERC by MISO and SPP. In March 2014, FERC issued an order setting all of the cases for settlement judge proceedings, or hearings if settlement fails. The Xcel Energy utilities have intervened in the various dockets, arguing that non-firm use by MISO should not be subject to SPP transmission charges. If SPP is successful in charging MISO for use of the SPP system, the NSP System would experience higher costs from MISO, which could be material, but SPS would collect revenues from SPP. The outcome of the JOA disputes, and the potential impact on Xcel Energy, are uncertain at this time. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to Jan. 29, 2014, and set the issues for settlement judge and hearing procedures.

FERC Order 745 Vacated, Demand Response Compensation in Organized Wholesale Energy Markets (Order 745) — In 2011, the FERC issued a final rule requiring that demand resources participating in organized wholesale markets (such as MISO) be paid the locational marginal price for avoided energy consumption. Numerous parties objected to the rule. On appeal, the D.C. Circuit Court of Appeals vacated and remanded FERC’s order. The Court found that the order was an impermissible intrusion by the FERC into retail electric matters reserved to the states. The FERC has requested rehearing en banc (review by the entire appeals court panel) and that request remains pending. After issuance of the Court’s decision, FirstEnergy Service Company (FirstEnergy) filed a complaint requesting FERC to require PJM to remove all portions of the PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s wholesale markets. This complaint also remains pending. Neither the Court’s vacatur of Order 745 nor FirstEnergy’s complaint against PJM have material implications for NSP-Minnesota and NSP-Wisconsin at this time. However, these actions create uncertainty regarding future participation of demand resources in the MISO wholesale organized market.


24


Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Wisconsin maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of June 30, 2014, based on an evaluation carried out under the supervision and with the participation of NSP-Wisconsin’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Wisconsin’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Wisconsin’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Wisconsin’s internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

NSP-Wisconsin is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the consolidated financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

NSP-Wisconsin’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2013, which is incorporated herein by reference.

Item 4MINE SAFETY DISCLOSURES

None.

Item 5OTHER INFORMATION

None.


25


Item 6 — EXHIBITS
*
Indicates incorporation by reference
3.01*
Amended and Restated Articles of Incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
3.02*
By-Laws of Northern States Power Co. (a Wisconsin corporation) as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03140)).

4.01*
Supplemental Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.30 percent First Mortgage Bonds, Series due June 15, 2024. (Exhibit 4.01 to NSP-Wisconsin’s Form 8-K dated June 23, 2014 (file no. 001-03140)).

Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Statement pursuant to Private Securities Litigation Reform Act of 1995.
101
The following materials from NSP-Wisconsin’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.

26


SIGNATURES

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.

 
 
Northern States Power Company (a Wisconsin corporation)
 
 
 
Aug. 4, 2014
By:
/s/ JEFFREY S. SAVAGE
 
 
Jeffrey S. Savage
 
 
Vice President and Controller
 
 
 
 
 
/s/ TERESA S. MADDEN
 
 
Teresa S. Madden
 
 
Senior Vice President, Chief Financial Officer and Director

27