NORTHERN STATES POWER CO /WI/, 10-K filed on 2/23/2015
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2014
Feb. 23, 2015
Jun. 30, 2014
Document and Entity Information [Abstract]
 
 
 
Entity Registrant Name
NORTHERN STATES POWER CO /WI/ 
 
 
Entity Central Index Key
0000072909 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2014 
 
 
Document Fiscal Year Focus
2014 
 
 
Document Fiscal Period Focus
FY 
 
 
Amendment Flag
false 
 
 
Entity Common Stock, Shares Outstanding
 
933,000 
 
Entity Well-known Seasoned Issuer
No 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Public Float
 
 
$ 0 
CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Operating revenues
 
 
 
Electric
$ 829,748 
$ 789,168 
$ 757,565 
Natural gas
169,629 
132,867 
103,100 
Other
1,085 
1,003 
1,177 
Total operating revenues
1,000,462 
923,038 
861,842 
Operating expenses
 
 
 
Electric fuel and purchased power, non-affiliates
19,595 
18,129 
19,440 
Purchased power, affiliates
425,471 
416,173 
405,016 
Cost of natural gas sold and transported
114,250 
81,572 
61,370 
Operating and maintenance expenses
191,213 
175,522 
167,503 
Conservation program expenses
11,537 
12,333 
14,442 
Depreciation and amortization
79,654 
76,897 
69,234 
Taxes (other than income taxes)
27,114 
25,231 
24,971 
Total operating expenses
868,834 
805,857 
761,976 
Operating income
131,628 
117,181 
99,866 
Other income, net
270 
253 
476 
Allowance for funds used during construction — equity
7,060 
4,259 
2,104 
Interest charges and financing costs
 
 
 
Interest charges — includes other financing costs of $1,570, $1,538, and $1,574, respectively
29,273 
27,797 
24,799 
Allowance for funds used during construction — debt
(3,360)
(1,981)
(1,862)
Total interest charges and financing costs
25,913 
25,816 
22,937 
Income before income taxes
113,045 
95,877 
79,509 
Income taxes
42,403 
36,409 
29,558 
Net income
$ 70,642 
$ 59,468 
$ 49,951 
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Interest charges and financing costs
 
 
 
Other financing costs
$ 1,570 
$ 1,538 
$ 1,574 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Comprehensive income:
 
 
 
Net income
$ 70,642 
$ 59,468 
$ 49,951 
Derivative instruments:
 
 
 
Reclassification of losses to net income, net of tax of $51, $51 and $51, respectively.
76 
76 
77 
Other comprehensive income
76 
76 
77 
Comprehensive income
$ 70,718 
$ 59,544 
$ 50,028 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Derivative instruments:
 
 
 
Reclassification of losses to net income, net of tax
$ (51)
$ (51)
$ (51)
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Operating activities
 
 
 
Net income
$ 70,642 
$ 59,468 
$ 49,951 
Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
80,875 
78,048 
70,372 
Deferred income taxes
45,396 
25,789 
27,107 
Amortization of investment tax credits
(527)
(664)
(626)
Allowance for equity funds used during construction
(7,060)
(4,259)
(2,104)
Provision for bad debts
4,431 
3,988 
3,329 
Net derivative losses (gains)
10 
(279)
127 
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(5,558)
(12,702)
(15,953)
Accrued unbilled revenues
(1,933)
(2,496)
(470)
Inventories
(3,210)
(1,879)
6,018 
Other current assets
(3,501)
(3,749)
(3,172)
Accounts payable
2,936 
(1,811)
5,828 
Net regulatory assets and liabilities
(34,697)
(2,062)
3,623 
Other current liabilities
(911)
7,589 
3,681 
Pension and other employee benefit obligations
(6,134)
(8,759)
(10,857)
Change in other noncurrent assets
(113)
232 
14 
Change in other noncurrent liabilities
2,534 
1,119 
(595)
Net cash provided by operating activities
143,180 
137,573 
136,273 
Investing activities
 
 
 
Utility capital/construction expenditures
(288,209)
(201,278)
(152,759)
Allowance for equity funds used during construction
7,060 
4,259 
2,104 
Other, net
(166)
(421)
916 
Net cash used in investing activities
(281,315)
(197,440)
(149,739)
Financing activities
 
 
 
Proceeds from (repayments of) short-term borrowings, net
10,000 
29,000 
(27,000)
Proceeds from notes payable to affiliates
30 
0 
50 
Repayments Of Notes Payable To Affiliates
0 
(80)
0 
Proceeds from Issuance of Long-term Debt
98,534 
0 
97,916 
Repayments of long-term debt
(107)
(160)
(97)
Capital contributions from parent
73,432 
58,977 
2,796 
Dividends paid to parent
(43,818)
(30,980)
(57,311)
Net cash provided by financing activities
138,071 
56,757 
16,354 
Net change in cash and cash equivalents
(64)
(3,110)
2,888 
Cash and cash equivalents at beginning of period
1,349 
4,459 
1,571 
Cash and cash equivalents at end of period
1,285 
1,349 
4,459 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
(24,442)
(24,376)
(21,035)
Cash received (paid) for income taxes, net
3,474 
(9,842)
(5,841)
Supplemental disclosure of non-cash investing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$ 35,267 
$ 27,222 
$ 10,618 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Current assets
 
 
Cash and cash equivalents
$ 1,285 
$ 1,349 
Accounts receivable, net
60,396 1
59,269 1
Accrued unbilled revenues
53,567 
51,634 
Inventories
24,685 
21,475 
Regulatory assets
20,036 
14,866 
Prepaid taxes
28,628 
27,518 
Deferred income taxes
8,201 
14,953 
Prepayments and other
6,918 
5,056 
Total current assets
203,716 
196,120 
Property, plant and equipment, net
1,674,281 
1,442,779 
Other assets
 
 
Regulatory assets
280,693 
233,193 
Other investments
3,818 
3,650 
Other
4,612 
3,651 
Total other assets
289,123 
240,494 
Total assets
2,167,120 
1,879,393 
Current liabilities
 
 
Current portion of long-term debt
1,235 
107 
Short-term debt
78,000 
68,000 
Notes payable to affiliates
500 
470 
Accounts payable
61,530 
52,086 
Accounts payable to affiliates
26,524 
24,986 
Dividends payable to parent
14,957 
8,032 
Regulatory liabilities
16,940 
9,717 
Environmental liabilities
29,116 
28,785 
Other
19,923 
22,521 
Total current liabilities
248,725 
214,704 
Deferred credits and other liabilities
 
 
Deferred income taxes
348,180 
305,139 
Deferred investment tax credits
9,089 
9,698 
Regulatory liabilities
132,674 
126,424 
Environmental liabilities
78,620 
79,703 
Customer advances
17,623 
16,008 
Pension and employee benefit obligations
51,313 
45,708 
Other
16,151 
9,237 
Total deferred credits and other liabilities
653,650 
591,917 
Commitments and contingencies
   
   
Capitalization
 
 
Long-term debt
567,056 
468,490 
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2014 and 2013, respectively
93,300 
93,300 
Additional paid in capital
322,276 
248,844 
Retained earnings
282,398 
262,499 
Accumulated other comprehensive loss
(285)
(361)
Total common stockholder’s equity
697,689 
604,282 
Total liabilities and equity
$ 2,167,120 
$ 1,879,393 
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)
Dec. 31, 2014
Dec. 31, 2013
Capitalization
 
 
Common stock, shares authorized (in shares)
1,000,000 
1,000,000 
Common stock, par value (in dollars per share)
$ 100 
$ 100 
Common stock, shares outstanding (in shares)
933,000 
933,000 
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common stock
Additional Paid In Capital
Retained Earnings
Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2011
$ 521,153 
$ 93,300 
$ 187,071 
$ 241,296 
$ (514)
Balance (in shares) at Dec. 31, 2011
 
933,000 
 
 
 
Comprehensive income:
 
 
 
 
 
Net income
49,951 
 
 
49,951 
 
Other comprehensive income
77 
 
 
 
77 
Common dividends declared to parent
(56,871)
 
 
(56,871)
 
Contribution of capital by parent
2,796 
 
2,796 
 
 
Ending Balance at Dec. 31, 2012
517,106 
93,300 
189,867 
234,376 
(437)
Balance (in shares) at Dec. 31, 2012
 
933,000 
 
 
 
Comprehensive income:
 
 
 
 
 
Net income
59,468 
 
 
59,468 
 
Other comprehensive income
76 
 
 
 
76 
Common dividends declared to parent
(31,345)
 
 
(31,345)
 
Contribution of capital by parent
58,977 
 
58,977 
 
 
Ending Balance at Dec. 31, 2013
604,282 
93,300 
248,844 
262,499 
(361)
Balance (in shares) at Dec. 31, 2013
933,000 
933,000 
 
 
 
Comprehensive income:
 
 
 
 
 
Net income
70,642 
 
 
70,642 
 
Other comprehensive income
76 
 
 
 
76 
Common dividends declared to parent
(50,743)
 
 
(50,743)
 
Contribution of capital by parent
73,432 
 
73,432 
 
 
Ending Balance at Dec. 31, 2014
$ 697,689 
$ 93,300 
$ 322,276 
$ 282,398 
$ (285)
Balance (in shares) at Dec. 31, 2014
933,000 
933,000 
 
 
 
CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Unamortized discount
$ (2,519)
$ (2,321)
Total long-term debt, including current maturities
568,291 
468,597 
Less: current maturities
1,235 
107 
Total long-term debt
567,056 
468,490 
Common Stockholders' Equity
 
 
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2014 and 2013, respectively
93,300 
93,300 
Additional paid in capital
322,276 
248,844 
Retained earnings
282,398 
262,499 
Accumulated other comprehensive loss
(285)
(361)
Total common stockholder’s equity
697,689 
604,282 
First Mortgage Bonds [Member] |
Series Due Oct. 1, 2018 [Member]
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
150,000 
150,000 
First Mortgage Bonds [Member] |
Series Due June 15, 2024
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
100,000 
0 
First Mortgage Bonds [Member] |
Series Due Sept. 1, 2038 [Member]
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
200,000 
200,000 
First Mortgage Bonds [Member] |
Series Due Oct. 1, 2042
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
100,000 
100,000 
City of La Crosse Resource Recovery Bond [Member] |
Series Due Nov. 1, 2021 [Member]
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
18,600 1
18,600 1
Fort McCoy System Acquisition [Member] |
Due Oct. 15, 2030 [Member]
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
523 
558 
Other
 
 
Schedule of Capitalization, Long-term Debt [Line Items]
 
 
Long-term debt, gross
$ 1,687 
$ 1,760 
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical)
12 Months Ended
Dec. 31, 2014
First Mortgage Bonds [Member] |
Series Due Oct. 1, 2018 [Member]
 
Long-Term Debt
 
Debt instrument, interest rate stated percentage (in hundredths)
5.25% 
Debt instrument, maturity date
Oct. 01, 2018 
First Mortgage Bonds [Member] |
Series Due June 15, 2024
 
Long-Term Debt
 
Debt instrument, interest rate stated percentage (in hundredths)
3.30% 
Debt instrument, maturity date
Jun. 15, 2024 
First Mortgage Bonds [Member] |
Series Due Sept. 1, 2038 [Member]
 
Long-Term Debt
 
Debt instrument, interest rate stated percentage (in hundredths)
6.375% 
Debt instrument, maturity date
Sep. 01, 2038 
First Mortgage Bonds [Member] |
Series Due Oct. 1, 2042
 
Long-Term Debt
 
Debt instrument, interest rate stated percentage (in hundredths)
3.70% 
Debt instrument, maturity date
Oct. 01, 2042 
City of La Crosse Resource Recovery Bond [Member] |
Series Due Nov. 1, 2021 [Member]
 
Long-Term Debt
 
Debt instrument, interest rate stated percentage (in hundredths)
6.00% 
Debt instrument, maturity date
Nov. 01, 2021 
Fort McCoy System Acquisition [Member] |
Due Oct. 15, 2030 [Member]
 
Long-Term Debt
 
Debt instrument, interest rate stated percentage (in hundredths)
7.00% 
Debt instrument, maturity date
Oct. 15, 2030 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary.  In the consolidation process, all intercompany transactions and balances are eliminated.

NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary.  NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting — NSP-Wisconsin accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
•
Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows.  See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  NSP-Wisconsin presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas costs.  These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically, for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased electric energy and fuel for electric generation. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.

Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems.  NSP-Wisconsin recovers approved conservation program costs in base rate revenue.

NSP-Wisconsin is required to contribute 1.2 percent of its annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates on the customer utility bills. There is no financial incentive given back to the utility. The PSCW has full oversight of Focus on Energy including auditing and verification of programs. The program portfolio is outsourced to a third-party administrator who subcontracts as necessary to implement programs.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.3, 3.5 and 3.5 percent for the years ended Dec. 31, 2014, 2013 and 2012, respectively.

Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.

AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.

Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  NSP-Wisconsin uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

NSP-Wisconsin follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  NSP-Wisconsin recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Wisconsin reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense.  NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.

Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. See Note 9 for further discussion.

Cash and Cash Equivalents — NSP-Wisconsin considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Inventory — All inventory is recorded at average cost.

RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. NSP-Wisconsin acquires RECs from the generation or purchase of renewable power.  

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in electric fuel and purchased power expense.

Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. NSP-Wisconsin follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2014 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Accounting Pronouncements
Accounting Pronouncements
Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (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.
Selected Balance Sheet Data
Selected Balance Sheet Data
Selected Balance Sheet Data
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Accounts receivable, net (a)
 
 
 
 
Accounts receivable
 
66,217

 
64,180

Less allowance for bad debts
 
(5,821
)
 
(4,911
)
 
 
60,396

 
59,269



(a) 
Accounts receivable, net includes an immaterial amount and $1,595 due from affiliates for 2014 and 2013, respectively.
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Inventories
 
 
 
 
Materials and supplies
 
$
6,494

 
$
6,437

Fuel
 
6,654

 
5,915

Natural gas
 
11,537

 
9,123

 
 
$
24,685

 
$
21,475


(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
2,061,669

 
$
1,913,354

Natural gas plant
 
255,465

 
236,047

Common and other property
 
125,938

 
112,886

CWIP
 
231,413

 
127,954

Total property, plant and equipment
 
2,674,485

 
2,390,241

Less accumulated depreciation
 
(1,000,204
)
 
(947,462
)
 
 
$
1,674,281

 
$
1,442,779

Borrowings and Other Financing Instruments
Borrowings and Other Financing Instruments
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 Dec. 31, 2014
Borrowing limit
 
$
150

Amount outstanding at period end
 
78

Average amount outstanding
 
34

Maximum amount outstanding
 
80

Weighted average interest rate, computed on a daily basis
 
0.37
%
Weighted average interest rate at period end
 
0.55


(Amounts in Millions, Except Interest Rates)
 
Twelve Months Ended Dec. 31, 2014
 
Twelve Months Ended Dec. 31, 2013
 
Twelve Months Ended Dec. 31, 2012
Borrowing limit
 
$
150

 
$
150

 
$
150

Amount outstanding at period end
 
78

 
68

 
39

Average amount outstanding
 
46

 
20

 
61

Maximum amount outstanding
 
101

 
71

 
116

Weighted average interest rate, computed on a daily basis
 
0.27
%
 
0.31
%
 
0.39
%
Weighted average interest rate at period end
 
0.55

 
0.27

 
0.40



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 Dec. 31, 2014 and 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.

Amended Credit Agreement — In October 2014, NSP-Wisconsin entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for NSP-Wisconsin remained at $150 million.

NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

Other features of NSP-Wisconsin’s credit facility include:

•
The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. NSP-Wisconsin was in compliance as its debt-to-total capitalization ratio was 48 percent and 47 percent at Dec. 31, 2014 and 2013, respectively. If NSP-Wisconsin does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.
•
The credit facility has a cross-default provision that provides NSP-Wisconsin will be in default on its borrowings under the facility if NSP-Wisconsin or any of its subsidiaries whose total assets exceed 15 percent of NSP-Wisconsin’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.
•
The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.
•
The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

At Dec. 31, 2014, NSP-Wisconsin had the following committed credit facility available (in millions):
Credit Facility (a)
 
Drawn (b)
 
Available
$
150.0

 
$
78.0

 
$
72.0


(a) 
These credit facilities have been amended to extend the maturity to October 2019.
(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 Dec. 31, 2014 and 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)
 
Dec. 31, 2014
 
Dec. 31, 2013
Notes payable to affiliates
 
$
0.5

 
$
0.5

Weighted average interest rate
 
0.51
%
 
0.24
%


Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal property of NSP-Wisconsin is subject to the liens of its first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

During the next five years, NSP-Wisconsin has long-term debt maturities of $150 million due in 2018.

Deferred Financing Costs — Other assets included deferred financing costs of approximately $4.3 million and $3.5 million, net of amortization, at Dec. 31, 2014 and 2013, respectively.  NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions — NSP-Wisconsin’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of approximately $33.3 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements.  NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 52.8 percent at Dec. 31, 2014 and $8.3 million in retained earnings was not restricted.
Joint Ownership of Transmission Facilities
Joint Ownership of Transmission Facilities
Joint Ownership of Transmission Facilities

Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2014:
(Thousands of Dollars)
 
Plant in
Service
 
Accumulated Depreciation
 
CWIP
 
Ownership %
Electric Transmission:
 
 
 
 
 
 
 
 
CapX2020 Transmission
 
$
26,434

 
$
8,082

 
$
103,940

 
80.7
%
La Crosse, Wis. to Madison, Wis.
 
—

 
—

 
9,814

 
50.0

Total NSP-Wisconsin
 
$
26,434

 
$
8,082

 
$
113,754

 
 


NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.
Income Taxes
Income Taxes
Income Taxes

Tax Increase Prevention Act of 2014 — In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:
•
The R&E credit was extended for 2014;
•
PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and
•
50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

American Taxpayer Relief Act of 2012 — In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following:

•
The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains;
•
The R&E credit was extended for 2012 and 2013;
•
PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and
•
50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for in the period of enactment.

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 March 2016. In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. At Dec. 31, 2014, the IRS has begun the Appeals process; however, 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 Dec. 31, 2014, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. In the first quarter of 2014, the state of Wisconsin commenced an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of Dec. 31, 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 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)
 
Dec. 31, 2014
 
Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions
 
$
0.1

 
$
0.1

Unrecognized tax benefit — Temporary tax positions
 
2.9

 
1.4

Total unrecognized tax benefit
 
$
3.0

 
$
1.5



A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
2014
 
2013
 
2012
Balance at Jan. 1
 
$
1.5

 
$
1.3

 
$
1.5

Additions based on tax positions related to the current year
 
1.9

 
0.7

 
0.5

Reductions based on tax positions related to the current year
 
(0.2
)
 
—

 
(0.2
)
Additions for tax positions of prior years
 
0.1

 
0.5

 
0.3

Reductions for tax positions of prior years
 
(0.2
)
 
—

 
(0.8
)
Settlements with taxing authorities
 
(0.1
)
 
(1.0
)
 
—

Balance at Dec. 31
 
$
3.0

 
$
1.5

 
$
1.3



The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
NOL and tax credit carryforwards
 
$
(0.9
)
 
$
(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 Appeals process 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.

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 Dec. 31, 2014, 2013 and 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2014, 2013 or 2012.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)
 
2014
 
2013
Federal NOL carryforward
 
48.5

 
46.8

Federal tax credit carryforwards
 
4.5

 
4.4

State NOL carryforward
 
3.4

 
6.3



The federal carryforward periods expire between 2021 and 2034.  The state carryforward periods expire between 2022 and 2031.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
 
 
2014
 
2013
 
2012
Federal statutory rate
 
35.0
 %
 
35.0
 %
 
35.0
 %
Increases (decreases) in tax from:
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
 
4.9

 
5.0

 
3.4

Tax credits recognized
 
(0.7
)
 
(0.9
)
 
(0.9
)
Regulatory differences — utility plant items
 
(1.6
)
 
(0.9
)
 
(0.3
)
Change in unrecognized tax benefits
 
—

 
—

 
0.1

Other, net
 
(0.1
)
 
(0.2
)
 
(0.1
)
Effective income tax rate
 
37.5
 %
 
38.0
 %
 
37.2
 %


The components of income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Current federal tax expense (benefit)
 
$
(3,932
)
 
$
5,902

 
$
930

Current state tax expense
 
453

 
4,628

 
2,216

Current change in unrecognized tax expense (benefit)
 
1,013

 
754

 
(69
)
Deferred federal tax expense
 
38,321

 
23,794

 
25,089

Deferred state tax expense
 
8,042

 
2,720

 
1,890

Deferred change in unrecognized tax (benefit) expense
 
(967
)
 
(725
)
 
128

Deferred investment tax credits
 
(527
)
 
(664
)
 
(626
)
Total income tax expense
 
$
42,403

 
$
36,409

 
$
29,558


The components of deferred income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Deferred tax expense excluding items below
 
$
49,793

 
$
27,516

 
$
27,995

Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
 
(4,346
)
 
(1,676
)
 
(837
)
Tax expense allocated to other comprehensive income
 
(51
)
 
(51
)
 
(51
)
Deferred tax expense
 
$
45,396

 
$
25,789

 
$
27,107



The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:
(Thousands of Dollars)
 
2014
 
2013
Deferred tax liabilities:
 
 
 
 
Difference between book and tax bases of property
 
$
319,265

 
$
287,121

Regulatory assets
 
72,670

 
57,296

Employee benefits
 
18,691

 
16,953

Other
 
14,453

 
10,193

Total deferred tax liabilities
 
$
425,079

 
$
371,563

Deferred tax assets:
 
 
 
 
Environmental remediation
 
43,207

 
43,501

NOL carryforward
 
18,283

 
17,384

Regulatory liabilities
 
10,460

 
6,205

Deferred investment tax credits
 
5,628

 
5,976

Tax credit carryforward
 
4,515

 
4,440

Other
 
3,007

 
3,871

Total deferred tax assets
 
$
85,100

 
$
81,377

Net deferred tax liability
 
$
339,979

 
$
290,186

Benefit Plans and Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Wisconsin accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. NSP-Wisconsin is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Wisconsin accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Wisconsin employees.

Xcel Energy, which includes NSP-Wisconsin, offers various benefit plans to its employees. Approximately 71 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2014, NSP-Wisconsin had 402 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs 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.

Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Pension Benefits

Xcel Energy, which includes NSP-Wisconsin, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and NSP-Wisconsin’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2014 and 2013 were $46.5 million and $36.5 million, respectively, of which $0.8 million and $0.6 million, respectively, was attributable to NSP-Wisconsin. In 2014 and 2013, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4.7 million and $6.6 million, respectively, of which amounts attributable to NSP-Wisconsin were immaterial. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

•
Investment returns in 2014 and 2013 were below the assumed level of 7.25 percent in both years;
•
Investment returns in 2012 were above the assumed level of 7.50 percent; and
•
In 2015, NSP-Wisconsin’s expected investment-return assumption is 7.25 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Wisconsin’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2014
 
2013
Domestic and international equity securities
 
39
%
 
31
%
Long-duration fixed income and interest rate swap securities
 
23

 
29

Short-to-intermediate term fixed income securities
 
14

 
16

Alternative investments
 
22

 
22

Cash
 
2

 
2

Total
 
100
%
 
100
%


The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:
 
 
Dec. 31, 2014
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
7,910

 
$
—

 
$
—

 
$
7,910

Derivatives
 
—

 
28

 
—

 
28

Government securities
 
—

 
16,084

 
—

 
16,084

Corporate bonds
 
—

 
13,231

 
—

 
13,231

Asset-backed securities
 
—

 
162

 
—

 
162

Mortgage-backed securities
 
—

 
475

 
—

 
475

Common stock
 
4,424

 
—

 
—

 
4,424

Private equity investments
 
—

 
—

 
7,078

 
7,078

Commingled funds
 
—

 
81,806

 
—

 
81,806

Real estate
 
—

 
—

 
2,510

 
2,510

Securities lending collateral obligation and other
 
—

 
(995
)
 
—

 
(995
)
Total
 
$
12,334

 
$
110,791

 
$
9,588

 
$
132,713

 
 
Dec. 31, 2013
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
4,332

 
$
—

 
$
—

 
$
4,332

Derivatives
 
—

 
937

 
—

 
937

Government securities
 
—

 
6,711

 
—

 
6,711

Corporate bonds
 
—

 
24,955

 
—

 
24,955

Asset-backed securities
 
—

 
307

 
—

 
307

Mortgage-backed securities
 
—

 
684

 
—

 
684

Common stock
 
4,533

 
—

 
—

 
4,533

Private equity investments
 
—

 
—

 
7,502

 
7,502

Commingled funds
 
—

 
84,364

 
—

 
84,364

Real estate
 
—

 
—

 
2,299

 
2,299

Securities lending collateral obligation and other
 
—

 
311

 
—

 
311

Total
 
$
8,865

 
$
118,269

 
$
9,801

 
$
136,935



The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:
(Thousands of Dollars)
 
Jan. 1, 2014
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfer Out
of Level 3
 
Dec. 31, 2014
Private equity investments
 
$
7,502

 
$
1,197

 
$
(1,197
)
 
$
(424
)
 
$
—

 
$
7,078

Real estate
 
2,299

 
166

 
(234
)
 
279

 
—

 
2,510

Total
 
$
9,801

 
$
1,363

 
$
(1,431
)
 
$
(145
)
 
$
—

 
$
9,588


(Thousands of Dollars)
 
Jan. 1, 2013
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3 (a)
 
Dec. 31, 2013
Asset-backed securities
 
$
749

 
$
—

 
$
—

 
$
—

 
$
(749
)
 
$
—

Mortgage-backed securities
 
2,128

 
—

 
—

 
—

 
(2,128
)
 
—

Private equity investments
 
8,545

 
1,083

 
(1,960
)
 
(166
)
 
—

 
7,502

Real estate
 
3,472

 
(129
)
 
247

 
450

 
(1,741
)
 
2,299

Total
 
$
14,894

 
$
954

 
$
(1,713
)
 
$
284

 
$
(4,618
)
 
$
9,801



(a) 
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
(Thousands of Dollars)
 
Jan. 1, 2012
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3
 
Dec. 31, 2012
Asset-backed securities
 
$
1,578

 
$
197

 
$
(273
)
 
$
(753
)
 
$
—

 
$
749

Mortgage-backed securities
 
3,781

 
93

 
(112
)
 
(1,634
)
 
—

 
2,128

Private equity investments
 
8,440

 
945

 
(1,197
)
 
357

 
—

 
8,545

Real estate
 
2,008

 
1

 
328

 
1,135

 
—

 
3,472

Total
 
$
15,807

 
$
1,236

 
$
(1,254
)
 
$
(895
)
 
$
—

 
$
14,894



Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2014
 
2013
Accumulated Benefit Obligation at Dec. 31
 
$
153,590

 
$
153,894

 
 
 
 
 
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
163,930

 
$
179,995

Service cost
 
4,527

 
5,682

Interest cost
 
7,257

 
6,924

Plan amendments
 
—

 
(1,109
)
Actuarial loss (gain)
 
9,126

 
(11,097
)
Benefit payments
 
(19,171
)
 
(16,465
)
Obligation at Dec. 31
 
$
165,669

 
$
163,930


(Thousands of Dollars)
 
2014
 
2013
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
136,935

 
$
136,546

Actual return on plan assets
 
6,916

 
5,525

Employer contributions
 
8,033

 
11,329

Benefit payments
 
(19,171
)
 
(16,465
)
Fair value of plan assets at Dec. 31
 
$
132,713

 
$
136,935


(Thousands of Dollars)
 
2014
 
2013
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status (a)
 
$
(32,956
)
 
$
(26,995
)

(a) 
Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
90,007

 
$
84,773

Prior service cost
 
667

 
778

Total
 
$
90,674

 
$
85,551


(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
 
 
 
 
Current regulatory assets
 
$
6,728

 
$
7,631

Noncurrent regulatory assets
 
83,946

 
77,920

Total
 
$
90,674

 
$
85,551


Measurement date
 
Dec. 31, 2014
 
Dec. 31, 2013
 
 
2014
 
2013
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.11
%
 
4.75
%
Expected average long-term increase in compensation level
 
3.75

 
3.75

Mortality table
 
RP 2014

 
RP 2000



Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. NSP-Wisconsin has reviewed its own population through a credibility analysis and adopted the RP 2014 table with modifications based on its population and specific experience.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2012 through 2015 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•
$90.0 million in January 2015, of which $4.9 million was attributable to NSP-Wisconsin;
•
$130.6 million in 2014, of which $8.0 million was attributable to NSP-Wisconsin;
•
$192.4 million in 2013, of which $11.3 million was attributable to NSP-Wisconsin; and
•
$198.1 million in 2012, of which $12.5 million was attributable to NSP-Wisconsin.

For future years, Xcel Energy and NSP-Wisconsin anticipate contributions will be made as necessary.

Plan Amendments — In 2014, there were no plan amendments made which affected the benefit obligation. Xcel Energy, which includes NSP-Wisconsin, amended the plan in 2013 resulting in a decrease of the projected benefit obligation due to fully insuring the long-term disability benefit for NSP bargaining participants. This decrease was partially offset by an increase to the projected benefit obligation resulting from a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan.

Benefit Costs — The components of NSP-Wisconsin’s net periodic pension cost were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Service cost
 
$
4,527

 
$
5,682

 
$
4,568

Interest cost
 
7,257

 
6,924

 
7,765

Expected return on plan assets
 
(9,642
)
 
(9,995
)
 
(10,489
)
Amortization of prior service cost
 
111

 
417

 
1,771

Amortization of net loss
 
6,617

 
7,924

 
6,004

Net periodic pension cost
 
$
8,870

 
$
10,952

 
$
9,619


 
 
2014
 
2013
 
2012
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.75
%
 
4.00
%
 
5.00
%
Expected average long-term increase in compensation level
 
3.75

 
3.75

 
4.00

Expected average long-term rate of return on assets
 
7.25

 
7.25

 
7.50



In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to NSP-Wisconsin were $1.7 million, $2.2 million and $1.8 million in 2014, 2013 and 2012, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2015 pension cost calculations is 7.25 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including NSP-Wisconsin, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes NSP-Wisconsin, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for NSP-Wisconsin was approximately $1.4 million in 2014, $1.3 million in 2013 and $1.2 million in 2012.

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Wisconsin, has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. The former NSP, which includes NSP-Wisconsin, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

In 1993, Xcel Energy Inc. and NSP-Wisconsin adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.

Regulatory agencies for nearly all retail utility customers have allowed rate recovery of accrued postretirement benefit costs.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2014
 
2013
Domestic and international equity securities
 
25
%
 
41
%
Short-to-intermediate fixed income securities
 
57

 
40

Alternative investments
 
13

 
13

Cash
 
5

 
6

Total
 
100
%
 
100
%


Xcel Energy Inc. and NSP-Wisconsin base investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Wisconsin’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility is not considered to be a material factor in postretirement health care costs.

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:
 
 
Dec. 31, 2014
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
28

 
$
—

 
$
—

 
$
28

Government securities
 
—

 
52

 
—

 
52

Insurance contracts
 
—

 
54

 
—

 
54

Corporate bonds
 
—

 
59

 
—

 
59

Asset-backed securities
 
—

 
4

 
—

 
4

Mortgage-backed securities
 
—

 
12

 
—

 
12

Commingled funds
 
—

 
304

 
—

 
304

Other
 
—

 
(1
)
 
—

 
(1
)
Total
 
$
28

 
$
484

 
$
—

 
$
512

 
 
Dec. 31, 2013
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
31

 
$
—

 
$
—

 
$
31

Derivatives
 
—

 
(2
)
 
—

 
(2
)
Government securities
 
—

 
89

 
—

 
89

Insurance contracts
 
—

 
80

 
—

 
80

Corporate bonds
 
—

 
79

 
—

 
79

Asset-backed securities
 
—

 
5

 
—

 
5

Mortgage-backed securities
 
—

 
37

 
—

 
37

Commingled funds
 
—

 
452

 
—

 
452

Other
 
—

 
(25
)
 
—

 
(25
)
Total
 
$
31

 
$
715

 
$
—

 
$
746



For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:
(Thousands of Dollars)
 
Jan. 1, 2013
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3 (a)
 
Dec. 31, 2013
Asset-backed securities
 
$
1

 
$
—

 
$
—

 
$
—

 
$
(1
)
 
$
—

Mortgage-backed securities
 
54

 
—

 
—

 
—

 
(54
)
 
—

Total
 
$
55

 
$
—

 
$
—

 
$
—

 
$
(55
)
 
$
—



(a) 
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
(Thousands of Dollars)
 
Jan. 1, 2012
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3
 
Dec. 31, 2012
Asset-backed securities
 
$
14

 
$
—

 
$
3

 
$
(16
)
 
$
—

 
$
1

Mortgage-backed securities
 
48

 
(1
)
 
6

 
1

 
—

 
54

Total
 
$
62

 
$
(1
)
 
$
9

 
$
(15
)
 
$
—

 
$
55



Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2014
 
2013
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
17,153

 
$
19,432

Service cost
 
35

 
25

Interest cost
 
791

 
760

Medicare subsidy reimbursements
 
2

 
31

Plan participants’ contributions
 
284

 
621

Actuarial gain
 
(38
)
 
(1,724
)
Benefit payments
 
(1,459
)
 
(1,992
)
Obligation at Dec. 31
 
$
16,768

 
$
17,153


(Thousands of Dollars)
 
2014
 
2013
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
746

 
$
647

Actual return on plan assets
 
(15
)
 
(13
)
Plan participants’ contributions
 
284

 
621

Employer contributions
 
956

 
1,483

Benefit payments
 
(1,459
)
 
(1,992
)
Fair value of plan assets at Dec. 31
 
$
512

 
$
746


(Thousands of Dollars)
 
2014
 
2013
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status
 
$
(16,256
)
 
$
(16,407
)
Current liabilities
 
(1,022
)
 
(718
)
Noncurrent liabilities
 
(15,234
)
 
(15,689
)
Net postretirement amounts recognized on consolidated balance sheets
 
$
(16,256
)
 
$
(16,407
)

(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
10,461

 
$
11,098

Prior service credit
 
(2,836
)
 
(3,187
)
Total
 
$
7,625

 
$
7,911


(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
 
 
 
 
Current regulatory assets
 
$
95

 
$
570

Noncurrent regulatory assets
 
7,530

 
7,341

Total
 
$
7,625

 
$
7,911


Measurement date
 
Dec. 31, 2014
 
Dec. 31, 2013
 
 
2014
 
2013
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.08
%
 
4.82
%
Mortality table
 
RP 2014

 
RP 2000

Health care costs trend rate — initial
 
6.50
%
 
7.00
%


Effective Jan. 1, 2015, the initial medical trend rate was decreased from 7.0 percent to 6.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is four years. Xcel Energy Inc. and NSP-Wisconsin base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin:
 
 
One-Percentage Point
(Thousands of Dollars)
 
Increase
 
Decrease
APBO
 
$
1,722

 
$
(1,450
)
Service and interest components
 
98

 
(80
)


Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes NSP-Wisconsin, contributed $17.1 million, $17.6 million and $47.1 million during 2014, 2013 and 2012, respectively, of which $1.0 million, $1.5 million and $1.9 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $12.8 million during 2015, of which $1.5 million is attributable to NSP-Wisconsin.

Plan Amendments — In 2014 and 2013, there were no plan amendments made which affected the benefit obligation.

Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit costs were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Service cost
 
$
35

 
$
25

 
$
20

Interest cost
 
791

 
760

 
1,075

Expected return on plan assets
 
(52
)
 
(42
)
 
(50
)
Amortization of transition obligation
 
—

 
1

 
171

Amortization of prior service credit
 
(351
)
 
(351
)
 
(14
)
Amortization of net loss
 
666

 
963

 
486

Net periodic postretirement benefit cost
 
$
1,089

 
$
1,356

 
$
1,688


 
 
2014
 
2013
 
2012
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.82
%
 
4.10
%
 
5.00
%
Expected average long-term rate of return on assets
 
7.08

 
7.11

 
6.75



In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs.

Projected Benefit Payments

The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans:
(Thousands of Dollars)
 
Projected Pension
Benefit Payments
 
Gross Projected
Postretirement
Health Care
Benefit Payments
 
Expected Medicare
Part D Subsidies
 
Net Projected
Postretirement
Health Care
Benefit Payments
2015
 
$
12,517

 
$
1,547

 
$
13

 
$
1,534

2016
 
13,288

 
1,473

 
11

 
1,462

2017
 
13,164

 
1,397

 
9

 
1,388

2018
 
12,564

 
1,352

 
8

 
1,344

2019
 
13,289

 
1,311

 
7

 
1,304

2020-2024
 
65,118

 
5,816

 
30

 
5,786



Multiemployer Plans

NSP-Wisconsin contributes to several union multiemployer pension plans, none of which are individually significant. These plans provide pension benefits to certain union employees, including electrical workers and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Wisconsin sponsored pension plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2014, 2013 and 2012. There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Multiemployer plan contributions:
 
 
 
 
 
 
Pension
 
$
156

 
$
130

 
$
163

Total
 
$
156

 
$
130

 
$
163

Other Income, Net
Other Income, Net
Other Income, Net

Other income, net for the years ended Dec. 31 consisted of the following:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Interest income
 
$
368

 
$
538

 
$
736

Other nonoperating income
 
321

 
152

 
129

Insurance policy expense
 
(409
)
 
(427
)
 
(389
)
Other nonoperating expense
 
(10
)
 
(10
)
 
—

Other income, net
 
$
270

 
$
253

 
$
476

Fair Value of Financial Assets and Liabilities
Fair Value of Financial Assets and Liabilities
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.

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, for trading purposes and 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 Dec. 31, 2014, accumulated other comprehensive losses 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, including forecasted amounts for unsettled hedges, as applicable.

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 Dec. 31:
(Amounts in Thousands) (a)(b)
 
2014
 
2013
MMBtu of natural gas
 
18

 
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.

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.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
 
$
(361
)
 
$
(437
)
 
$
(514
)
After-tax net realized losses on derivative transactions reclassified into earnings
 
76

 
76

 
77

Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
 
$
(285
)
 
$
(361
)
 
$
(437
)


Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for each of the years ended Dec. 31, 2014, 2013 and 2012.

During the year ended Dec. 31, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.1 million, recognized as regulatory assets and liabilities. During the years ended Dec. 31, 2013 and 2012, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million and $0.4 million, respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

During the year ended Dec. 31, 2014, immaterial natural gas commodity derivatives settlement gains were recognized and losses totaling $0.7 million and $2.9 million were recognized for each of the years ended Dec. 31, 2013 and 2012, 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.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2014, 2013 and 2012. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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:
 
 
Dec. 31, 2014
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (b)
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
52

 
$
—

 
$
52

 
$
—

 
$
52

 
 
Dec. 31, 2013
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (c)
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 Dec. 31, 2014 and 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 other current assets balance of $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.
(c) 
Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
 
2014
 
2013
(Thousands of Dollars)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt, including current portion
 
$
568,291

 
$
670,665

 
$
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 Dec. 31, 2014 and 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.
Rate Matters (Notes)
Rate Matters
Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

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 was 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 were requested to the capital structure or the 10.2 percent 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.

In December 2014, the PSCW issued its order approving an overall increase in NSP-Wisconsin’s electric rates of approximately $14.2 million, or 2.2 percent, reflecting the updated November forecast for fuel and purchased power costs. The PSCW order was consistent with the agreement reached by the parties, as described above. The new rates were effective Jan. 1, 2015.

Pending Regulatory Proceedings - Michigan Public Service Commission (MPSC)

Michigan 2015 Electric Rate Case — In October 2014, NSP-Wisconsin filed a request with the MPSC to increase rates for electric service by $900,000, or 6.1 percent. The filing was based on a 2015 forecast test year, a 10.3 percent ROE, an equity ratio of 52.59 percent and a forecasted average rate base of approximately $35.2 million. The primary drivers of the requested increase are continuing investment in transmission and distribution infrastructure. The filing also included a request for a $289,000, or 1.9 percent, step increase in 2016, to reflect the expiration in 2016 of certain credits that were used to offset the 2015 rate request. In addition to the MPSC staff, intervenors in the case include the Michigan Attorney General and the Association of Businesses Advocating Tariff Equity, a voluntary association of large industrial businesses. Hearings are scheduled for April 2015. The parties have agreed to meet in February 2015 to discuss potential settlement of the case.

Pending Regulatory Proceedings — FERC

MISO ROE Complaint/ROE Adder — 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 argued 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 RTO membership and being an independent transmission company), effective Nov. 12, 2013.

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.

In October 2014, the FERC upheld the determination of the long-term growth rate to be used together with a short term growth rate in its new ROE methodology. The FERC separately set the ROE complaint against the MISO transmission owners for settlement judge and hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. The settlement judge procedures were unsuccessful. FERC action is pending. In January 2015, the ROE complaint was set for full hearing procedures, with an ALJ initial decision to be issued by November 2015 and a FERC order issued no earlier than 2016.

In November 2014, the MISO transmission owners filed a request for FERC approval of a 50 basis point RTO membership ROE adder, with collection deferred until resolution of the ROE complaint. In January 2015, the FERC approved the ROE adder, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. In 2015, several intervenors sought rehearing of the commission order.

In February 2015, a separate group of customers filed an additional complaint proposing to reduce the MISO region ROE to 8.67 percent, prior to any 50 basis point RTO adder, with a refund effective date of Feb. 12, 2015.  Answers to the complaint are to be filed by March 2015.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of Dec. 31, 2014. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $5 million and $7 million annually for the NSP System.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies

Commitments

Fuel Contracts — NSP-Wisconsin has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2015 and 2029. In addition, NSP-Wisconsin is required to pay additional amounts depending on actual quantities shipped under these agreements. As NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers, NSP-Wisconsin utilizes deferred accounting treatment for future rate recovery or refund when fuel costs differ from the amount included in rates by more than two percent on an annual basis, as determined by the PSCW after an opportunity for a hearing and an earnings test based on NSP-Wisconsin’s authorized ROE.

The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2014 are as follows:
(Millions of dollars)
 
Coal
 
Natural gas
supply
 
Natural gas
storage and
transportation
2015
 
$
6.6

 
$
12.4

 
$
13.2

2016
 
0.8

 
0.3

 
13.1

2017
 
0.9

 
0.2

 
10.4

2018
 
0.8

 
—

 
4.7

2019
 
0.8

 
—

 
3.1

Thereafter
 
3.3

 
—

 
13.5

Total (a)
 
$
13.2

 
$
12.9

 
$
58.0


(a) 
Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs.

Leases — NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business. These leases, primarily for office space, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $1.3 million, $1.4 million and $1.1 million for 2014, 2013 and 2012, respectively.

Future commitments under operating leases are:
(Millions of Dollars)
 
 
2015
 
$
0.9

2016
 
0.9

2017
 
1.0

2018
 
1.0

2019
 
1.0

Thereafter
 
7.9

Total
 
$
12.7



Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

NSP-Wisconsin has entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. NSP-Wisconsin has determined the low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and NSP-Wisconsin generally receives a larger allocation of the tax credits than the general partners at inception of the arrangements. NSP-Wisconsin has determined that it has the power to direct the activities that most significantly impact these entities’ economic performance, and therefore NSP-Wisconsin consolidates these limited partnerships in its consolidated financial statements.

Equity financing for these entities has been provided by NSP-Wisconsin and the general partner of each limited partnership, and NSP-Wisconsin’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by NSP-Wisconsin. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to NSP-Wisconsin or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of NSP-Wisconsin or its subsidiaries.

Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following:
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Current assets
 
$
246

 
$
223

Property, plant and equipment, net
 
2,278

 
2,427

Other noncurrent assets
 
122

 
112

Total assets
 
$
2,646

 
$
2,762

 
 
 
 
 
Current liabilities
 
$
1,349

 
$
233

Mortgages and other long-term debt payable
 
486

 
1,687

Other noncurrent liabilities
 
48

 
42

Total liabilities
 
$
1,883

 
$
1,962



Joint Operating System — The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $13.6 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $127.3 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $19.0 million per reactor during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective September 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $17.9 million for business interruption insurance and $43.6 million for property damage insurance if losses exceed accumulated reserve funds.

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 the exposure of NSP-Wisconsin 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)
 
Guarantee
Amount
 
Current
Exposure
 
Term or
Expiration Date
 
Triggering
Event
Guarantee of customer loans for the Farm Rewiring Program
 
$
1.0

 
$
0.2

 
2018
 
(a) 

(a) 
The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Environmental Contingencies

NSP-Wisconsin has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Wisconsin is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Wisconsin, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, NSP-Wisconsin would be required to recognize an expense.

Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. NSP-Wisconsin may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by NSP-Wisconsin, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Wisconsin is alleged to be a PRP that sent hazardous materials and wastes to that site.

MGP Sites

Ashland MGP Site — NSP-Wisconsin has been named a 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 wood treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The 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.

In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future 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 WDNR, 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. 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 cost estimate for the cleanup of the Phase I Project Area is approximately $54 million, of which approximately $28 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. 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. It is NSP-Wisconsin’s view that 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. 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. In September 2014, the EPA granted an extension of time to perform the pilot in the summer of 2015.

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-May of 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. A settlement in principle has been reached with two PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”), the EPA and NSP-Wisconsin resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. Under the agreement, the Railroad PRPs have agreed to contribute $10.5 million to the costs of the cleanup at the Ashland site. The agreement is currently subject to a 30-day public comment period and must be entered by the U.S. District Court for the Western District of Wisconsin before it will become final. It is anticipated that the agreement will be entered in the first quarter of 2015. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers.

At Dec. 31, 2014 and 2013, NSP-Wisconsin had recorded a liability of $107.6 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 $28.9 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. Under the established PSCW policy, 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. Any payments received from insurance carriers or PRPs are recorded as a reduction of the regulatory asset. Once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four- to six-year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

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 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.

Other MGP Sites — NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited. NSP-Wisconsin has identified two sites where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the remediation at these sites will continue through at least 2015. NSP-Wisconsin had accrued $0.2 million and $3.9 million for both of these sites at Dec. 31, 2014 and 2013, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. NSP-Wisconsin anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste
Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Wisconsin has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

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) — Section 316(b) of 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. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Many of the compliance requirements depend on site-specific determinations by state regulators; therefore, the exact cost is somewhat uncertain. NSP-Wisconsin estimates the likely cost for complying with impingement requirements 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 second quarter of 2015.

Coal Ash Regulation — NSP-Wisconsin’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2010, the EPA published a proposed rule on the regulation of coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. The EPA issued a pre-publication version of the final rule in December 2014, which once promulgated will impose new rules to regulate coal ash as a nonhazardous solid waste. NSP-Wisconsin has ceased coal combustion at Bay Front Unit 5 and will not have any units subject to coal ash regulation. Due to the Interchange Agreement, NSP-Wisconsin may incur costs related to this rule but does not expect these to have a material impact on the results of operations, financial position or cash flows.

Air
GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments were due to the EPA on Dec. 1, 2014 and a final rule is anticipated in mid-summer 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.

GHG 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. A final rule is anticipated in mid-summer 2015. 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. A final rule is anticipated in mid-summer 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 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.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States, including Wisconsin, using 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 CSAPR’s predecessor rule 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 CAA 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 October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in February 2015. While the litigation continues, the EPA will begin to administer the CSAPR in 2015.

NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO2 due to cessation of coal combustion at Bay Front Unit 5. NSP-Wisconsin anticipates compliance with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. NSP-Wisconsin will not have any units subject to EGU MATS because it has ceased coal combustion in Bay Front Unit 5. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. It is not yet known what impact the Supreme Court’s decision may have on the MATS standard or its implementation schedule.

Industrial Boiler (IB) MACT Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The controls to meet the requirements were substantially complete as of Dec. 31, 2014, with final work targeted to be finished in May 2015. The final capital cost is estimated to be approximately $21 million.

Revisions to the National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where NSP-Wisconsin operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In December 2014, the EPA issued its final designations, which did not include areas in any states in which NSP-Wisconsin operates.

Revisions to the NAAQS for Ozone — In December 2014, the EPA proposed to revise the NAAQS for ozone by lowering the eight-hour standard from 0.075 parts per million (ppm) to a level within the range of 0.065-0.070 ppm. The EPA is also taking comment on a level for the standard as low as 0.060 ppm. Current monitored air quality concentrations in areas of Wisconsin where NSP-Wisconsin operates are below the range of the proposed standard. The EPA is expected to adopt a new ozone standard in a final rule to be issued in October 2015. Depending on the level of the standard, impacted states would study the sources of the nonattainment and make emission reduction plans to attain the standards. These plans would be due to the EPA in 2020 or 2021. Such plans could include installation of further NOx controls on power plants. It is not possible to evaluate the impact of this proposal until the final standard is adopted, the designation of nonattainment areas is made in late 2017 based on air quality data years 2014-2016, and any required state plans are developed.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, other and hydro), electric distribution and transmission, natural gas distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, storage tanks and control panels. The asbestos recognition associated with the electric production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for NSP-Wisconsin steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities.

NSP-Wisconsin has recognized an ARO for the retirement costs of natural gas mains and lines and for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

In December 2014, the EPA issued a pre-publication version of a final rule imposing requirements for activities involving coal ash waste. The ruling, once effective, will not result in the creation of a new legal obligation or impact NSP-Wisconsin’s estimated cash flows for the closure of coal ash landfills and impoundments.

A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2014 and 2013 is as follows:
(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2014
 
Liabilities Recognized
 
Accretion
 
Cash Flow Revisions
 
Ending Balance
Dec. 31, 2014 (a)
Electric plant
 
 
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
2,005

 
$
—

 
$
44

 
$
—

 
$
2,049

Steam and other production ash containment
 
361

 
—

 
13

 
—

 
374

Electric distribution
 
36

 
—

 
1

 
—

 
37

Other
 
289

 
113

 
10

 
—

 
412

Natural gas plant
 
 
 
 
 
 
 
 
 
 
Gas distribution
 
75

 
402

 
5

 
5,645

 
6,127

Common and other property
 
 
 
 
 
 
 
 
 
 
Common miscellaneous
 
87

 
—

 
3

 
1

 
91

Total liability (b)
 
$
2,853

 
$
515

 
$
76

 
$
5,646

 
$
9,090

(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2013
 
Liabilities Recognized
 
Accretion
 
Cash Flow Revisions
 
Ending Balance
Dec. 31, 2013 (a)
Electric plant
 
 
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
1,962

 
$
—

 
$
43

 
$
—

 
$
2,005

Steam and other production ash containment
 
125

 
—

 
12

 
224

 
361

Electric distribution
 
13

 
—

 
1

 
22

 
36

Other
 
826

 
—

 
20

 
(557
)
 
289

Natural gas plant
 
 
 
 
 
 
 
 
 
 
Gas distribution
 
75

 
—

 
5

 
(5
)
 
75

Common and other property
 
 
 
 
 
 
 
 
 
 
Common miscellaneous
 
35

 
—

 
3

 
49

 
87

Total liability (b)
 
$
3,036

 
$
—

 
$
84

 
$
(267
)
 
$
2,853


(a) 
There were no ARO liabilities settled during the years ended Dec. 31, 2014 or 2013.
(b) 
Included in the other long-term liabilities balance in the consolidated balance sheets.

Removal Costs — NSP-Wisconsin records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2014 and 2013 were $123 million and $116 million, respectively.

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.

Other Contingencies

See Note 10 for further discussion.
Regulatory Assets and Liabilities
Regulatory Assets and Liabilities
Regulatory Assets and Liabilities

NSP-Wisconsin’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities.  If changes in the utility industry or the business of NSP-Wisconsin no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2014 and 2013 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2014
 
Dec. 31, 2013
Regulatory Assets
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Environmental remediation costs
 
1, 11
 
Various
 
$
4,376

 
$
147,793

 
$
4,376

 
$
117,684

Pension and retiree medical obligations (a)
 
7
 
Various
 
6,837

 
91,601

 
8,202

 
85,220

Recoverable deferred taxes on AFUDC recorded in plant
 
1
 
Plant lives
 
—

 
16,711

 
—

 
12,679

Losses on reacquired debt
 
4
 
Term of related debt
 
801

 
4,936

 
801

 
5,737

State commission adjustments
 
1
 
Plant lives
 
488

 
11,650

 
410

 
9,355

Conservation programs
 
1
 
Less than one year
 
—

 
—

 
404

 
—

Deferred income tax adjustment
 
1, 6
 
Typically plant lives
 
—

 
1,514

 
—

 
1,763

Recoverable purchased natural gas and electric energy costs
 
 
 
Less than one year
 
6,946

 
—

 
673

 
—

Monticello EPU
 

 
Pending rate cases
 
—

 
5,237

 
—

 
—

Other
 
 
 
Various
 
588

 
1,251

 
—

 
755

Total regulatory assets
 
 
 
 
 
$
20,036

 
$
280,693

 
$
14,866

 
$
233,193


(a) 
Includes the non-qualified pension plan.

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2014 and 2013 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2014
 
Dec. 31, 2013
Regulatory Liabilities
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Plant removal costs
 
11
 
Plant lives
 
$
—

 
$
123,105

 
$
—

 
$
116,293

DOE settlement
 
11
 
Less than one year
 
4,931

 
—

 
6,814

 
—

Investment tax credit deferrals
 
1, 6
 
Various
 
—

 
9,397

 
—

 
9,976

Conservation programs
 
1
 
Less than one year
 
1,010

 
—

 
1,187

 
—

Deferred electric production and natural gas costs
 
1
 
Less than one year
 
—

 
—

 
1,542

 
—

Excess depreciation reserve
 
 
 
Various
 
10,999

 
—

 
—

 
—

Other
 
 
 
Various
 
—

 
172

 
174

 
155

Total regulatory liabilities
 
 
 
 
 
$
16,940

 
$
132,674

 
$
9,717

 
$
126,424



At Dec. 31, 2014 and 2013, approximately $12.1 million and $0.1 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes Monticello EPU costs and recoverable purchased natural gas and electric energy costs.
Other Comprehensive Income
Other Comprehensive Income
Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2014 and 2013 were as follows:
 
 
Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)
 
Year Ended Dec. 31, 2014
 
Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1
 
$
(361
)
 
$
(437
)
Losses reclassified from net accumulated other comprehensive loss
 
76

 
76

Net current period OCI
 
76

 
76

Accumulated other comprehensive loss at Dec. 31
 
$
(285
)
 
$
(361
)


Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:
 
 
Amounts Reclassified from Accumulated
Other Comprehensive Loss
 
(Thousands of Dollars)
 
Year Ended Dec. 31, 2014
 
Year Ended Dec. 31, 2013
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
127

(a) 
$
127

(a) 
Total, pre-tax
 
127

 
127

 
Tax benefit
 
(51
)
 
(51
)
 
Total amounts reclassified, net of tax
 
$
76

 
$
76

 

(a) 
Included in interest charges.
Segments and Related Information
Segment Information
Segments and Related 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 electricity which is transmitted and distributed in Wisconsin and Michigan.
•
NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas 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 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.

The accounting policies of the segments are the same as those described in Note 1.

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2014
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
829,748

 
$
169,629

 
$
1,085

 
$
—

 
$
1,000,462

Intersegment revenues
 
497

 
4,885

 
—

 
(5,382
)
 
—

Total revenues
 
$
830,245

 
$
174,514

 
$
1,085

 
$
(5,382
)
 
$
1,000,462

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
65,978

 
$
13,501

 
$
175

 
$
—

 
$
79,654

Interest charges and financing costs
 
23,448

 
2,358

 
107

 
—

 
25,913

Income tax expense (benefit)
 
39,621

 
5,993

 
(3,211
)
 
—

 
42,403

Net Income
 
59,060

 
8,714

 
2,868

 
—

 
70,642

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2013
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
789,168

 
$
132,867

 
$
1,003

 
$
—

 
$
923,038

Intersegment revenues
 
350

 
1,967

 
—

 
(2,317
)
 
—

Total revenues
 
$
789,518

 
$
134,834

 
$
1,003

 
$
(2,317
)
 
$
923,038

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
64,237

 
$
12,485

 
$
175

 
$
—

 
$
76,897

Interest charges and financing costs
 
22,966

 
2,749

 
101

 
—

 
25,816

Income tax expense (benefit)
 
33,691

 
4,623

 
(1,905
)
 
—

 
36,409

Net Income
 
51,334

 
6,501

 
1,633

 
—

 
59,468

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2012
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
757,565

 
$
103,100

 
$
1,177

 
$
—

 
$
861,842

Intersegment revenues
 
355

 
727

 
—

 
(1,082
)
 
—

Total revenues
 
$
757,920

 
$
103,827

 
$
1,177

 
$
(1,082
)
 
$
861,842

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
59,768

 
$
9,251

 
$
215

 
$
—

 
$
69,234

Interest charges and financing costs
 
20,303

 
2,554

 
80

 
—

 
22,937

Income tax expense
 
27,164

 
2,113

 
281

 
—

 
29,558

Net Income
 
45,377

 
3,094

 
1,480

 
—

 
49,951


(a) 
Operating revenues include $145 million, $137 million and $125 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012 respectively. See Note 15 for further discussion of related party transactions by operating segment.
Related Party Transactions
Related Party Transactions
Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Wisconsin. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Wisconsin uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Operating revenues:
 
 
 
 
 
 
Electric
 
$
145,102

 
$
136,917

 
$
125,344

Operating expenses:
 
 
 
 
 
 
Purchased power (a)
 
430,666

 
416,173

 
405,016

Transmission expense
 
43,876

 
42,460

 
44,942

Natural gas purchased for resale
 
90

 
97

 
116

Other operating expenses — paid to Xcel Energy Services Inc.
 
84,224

 
61,531

 
54,137

Interest expense
 
30

 
22

 
22


(a) 
Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

Accounts receivable and payable with affiliates at Dec. 31 were:
 
 
2014
 
2013
(Thousands of Dollars)
 
Accounts
Receivable
 
Accounts
Payable
 
Accounts
Receivable
 
Accounts
Payable
NSP-Minnesota
 
$
—

 
$
17,333

 
$
—

 
$
18,584

PSCo
 
—

 
22

 
—

 
8

SPS
 
31

 
—

 
26

 
—

Other subsidiaries of Xcel Energy Inc.
 
—

 
9,169

 
1,569

 
6,394

 
 
$
31

 
$
26,524

 
$
1,595

 
$
24,986

Schedule II, Valuation and Qualifying Accounts
Schedule II, Valuation and Qualifying Accounts
NSP-WISCONSIN AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2014, 2013 AND 2012
(amounts in thousands)
 
 
 
Additions
 
 
 
 
 
Balance at
Jan. 1
 
Charged to Costs and Expenses
 
Charged to Other
Accounts(a)
 
Deductions from 
Reserves(b)
 
Balance at
Dec. 31
Allowance for bad debts:
 
 
 
 
 
 
 
 
 
2014
$
4,911

 
$
4,431

 
$
1,269

 
$
4,790

 
$
5,821

2013
4,333

 
3,988

 
1,199

 
4,609

 
4,911

2012
4,766

 
3,329

 
1,310

 
5,072

 
4,333


(a) 
Recovery of amounts previously written off.
(b) 
Principally bad debts written off.
Summarized Quarterly Financial Data (Unaudited)
Summarized Quarterly Financial Data (Unaudited)
Summarized Quarterly Financial Data (Unaudited)
 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2014
 
June 30, 2014
 
Sept. 30, 2014
 
Dec. 31, 2014
Operating revenues
 
$
285,142

 
$
228,114

 
$
231,046

 
$
256,160

Operating income
 
42,571

 
23,730

 
37,540

 
27,787

Net income
 
24,235

 
12,022

 
20,030

 
14,355

 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2013
 
June 30, 2013
 
Sept. 30, 2013
 
Dec. 31, 2013
Operating revenues
 
$
241,415

 
$
210,175

 
$
231,060

 
$
240,388

Operating income
 
37,401

 
22,466

 
40,769

 
16,545

Net income
 
19,685

 
10,544

 
22,013

 
7,225

Summary of Significant Accounting Policies (Policies)
Business and System of Accounts 
Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation 
Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary.  In the consolidation process, all intercompany transactions and balances are eliminated.

NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary.  NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.
Use of Estimates 
Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting 
Regulatory Accounting — NSP-Wisconsin accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
•
Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows.  See Note 12 for further discussion of regulatory assets and liabilities.
Revenue Recognition 
Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  NSP-Wisconsin presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas costs.  These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically, for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Conservation Programs 
Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems.  NSP-Wisconsin recovers approved conservation program costs in base rate revenue.
Property, Plant and Equipment and Depreciation 
Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.3, 3.5 and 3.5 percent for the years ended Dec. 31, 2014, 2013 and 2012, respectively.
Leases 
Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.
AFUDC 
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.
Asset Retirement Obligations 
AROs —
Income Taxes 
Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  NSP-Wisconsin uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

NSP-Wisconsin follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  NSP-Wisconsin recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Wisconsin reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.
Types of and Accounting for Derivative Instruments 
Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense.  NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.
Fair Value Measurements 
Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. See Note 9 for further discussion.
Cash and Cash Equivalents 
Cash and Cash Equivalents — NSP-Wisconsin considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts 
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
Inventory 
Inventory — All inventory is recorded at average cost.
Renewable Energy Credits 
RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. NSP-Wisconsin acquires RECs from the generation or purchase of renewable power.  

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in electric fuel and purchased power expense.

Emission Allowances 
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. NSP-Wisconsin follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.
Environmental Costs 
Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits 
Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 7 for further discussion of benefit plans and other postretirement benefits.
Guarantees 
Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.
Subsequent Events 
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2014 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Selected Balance Sheet Data (Tables)
Accounts Receivable, Net 
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Accounts receivable, net (a)
 
 
 
 
Accounts receivable
 
66,217

 
64,180

Less allowance for bad debts
 
(5,821
)
 
(4,911
)
 
 
60,396

 
59,269



Inventories 
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Inventories
 
 
 
 
Materials and supplies
 
$
6,494

 
$
6,437

Fuel
 
6,654

 
5,915

Natural gas
 
11,537

 
9,123

 
 
$
24,685

 
$
21,475

Property, Plant and Equipment, Net 
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
2,061,669

 
$
1,913,354

Natural gas plant
 
255,465

 
236,047

Common and other property
 
125,938

 
112,886

CWIP
 
231,413

 
127,954

Total property, plant and equipment
 
2,674,485

 
2,390,241

Less accumulated depreciation
 
(1,000,204
)
 
(947,462
)
 
 
$
1,674,281

 
$
1,442,779

Borrowings and Other Financing Instruments (Tables)
Credit Facilities 
At Dec. 31, 2014, NSP-Wisconsin had the following committed credit facility available (in millions):
Credit Facility (a)
 
Drawn (b)
 
Available
$
150.0

 
$
78.0

 
$
72.0


(a) 
These credit facilities have been amended to extend the maturity to October 2019.
(b) 
Includes outstanding commercial paper.
Short-term Borrowings 
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 Dec. 31, 2014
Borrowing limit
 
$
150

Amount outstanding at period end
 
78

Average amount outstanding
 
34

Maximum amount outstanding
 
80

Weighted average interest rate, computed on a daily basis
 
0.37
%
Weighted average interest rate at period end
 
0.55


(Amounts in Millions, Except Interest Rates)
 
Twelve Months Ended Dec. 31, 2014
 
Twelve Months Ended Dec. 31, 2013
 
Twelve Months Ended Dec. 31, 2012
Borrowing limit
 
$
150

 
$
150

 
$
150

Amount outstanding at period end
 
78

 
68

 
39

Average amount outstanding
 
46

 
20

 
61

Maximum amount outstanding
 
101

 
71

 
116

Weighted average interest rate, computed on a daily basis
 
0.27
%
 
0.31
%
 
0.39
%
Weighted average interest rate at period end
 
0.55

 
0.27

 
0.40

Short-term Borrowings 
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)
 
Dec. 31, 2014
 
Dec. 31, 2013
Notes payable to affiliates
 
$
0.5

 
$
0.5

Weighted average interest rate
 
0.51
%
 
0.24
%
Joint Ownership of Transmission Facilities (Tables)
Investments in Jointly Owned Transmission Facilities
Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2014:
(Thousands of Dollars)
 
Plant in
Service
 
Accumulated Depreciation
 
CWIP
 
Ownership %
Electric Transmission:
 
 
 
 
 
 
 
 
CapX2020 Transmission
 
$
26,434

 
$
8,082

 
$
103,940

 
80.7
%
La Crosse, Wis. to Madison, Wis.
 
—

 
—

 
9,814

 
50.0

Total NSP-Wisconsin
 
$
26,434

 
$
8,082

 
$
113,754

 
 
Income Taxes (Tables)
Reconciliation of Unrecognized Tax Benefits 
A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions
 
$
0.1

 
$
0.1

Unrecognized tax benefit — Temporary tax positions
 
2.9

 
1.4

Total unrecognized tax benefit
 
$
3.0

 
$
1.5



A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
2014
 
2013
 
2012
Balance at Jan. 1
 
$
1.5

 
$
1.3

 
$
1.5

Additions based on tax positions related to the current year
 
1.9

 
0.7

 
0.5

Reductions based on tax positions related to the current year
 
(0.2
)
 
—

 
(0.2
)
Additions for tax positions of prior years
 
0.1

 
0.5

 
0.3

Reductions for tax positions of prior years
 
(0.2
)
 
—

 
(0.8
)
Settlements with taxing authorities
 
(0.1
)
 
(1.0
)
 
—

Balance at Dec. 31
 
$
3.0

 
$
1.5

 
$
1.3

Tax Benefits Associated with NOL and Tax Credit Carryforwards 
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
NOL and tax credit carryforwards
 
$
(0.9
)
 
$
(0.4
)
NOL and Tax Credit Carryforwards 
Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)
 
2014
 
2013
Federal NOL carryforward
 
48.5

 
46.8

Federal tax credit carryforwards
 
4.5

 
4.4

State NOL carryforward
 
3.4

 
6.3

Schedule of Effective Income Tax Rate Reconciliation 
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
 
 
2014
 
2013
 
2012
Federal statutory rate
 
35.0
 %
 
35.0
 %
 
35.0
 %
Increases (decreases) in tax from:
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
 
4.9

 
5.0

 
3.4

Tax credits recognized
 
(0.7
)
 
(0.9
)
 
(0.9
)
Regulatory differences — utility plant items
 
(1.6
)
 
(0.9
)
 
(0.3
)
Change in unrecognized tax benefits
 
—

 
—

 
0.1

Other, net
 
(0.1
)
 
(0.2
)
 
(0.1
)
Effective income tax rate
 
37.5
 %
 
38.0
 %
 
37.2
 %
Schedule of Components of Income Tax Expense (Benefit) 
The components of income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Current federal tax expense (benefit)
 
$
(3,932
)
 
$
5,902

 
$
930

Current state tax expense
 
453

 
4,628

 
2,216

Current change in unrecognized tax expense (benefit)
 
1,013

 
754

 
(69
)
Deferred federal tax expense
 
38,321

 
23,794

 
25,089

Deferred state tax expense
 
8,042

 
2,720

 
1,890

Deferred change in unrecognized tax (benefit) expense
 
(967
)
 
(725
)
 
128

Deferred investment tax credits
 
(527
)
 
(664
)
 
(626
)
Total income tax expense
 
$
42,403

 
$
36,409

 
$
29,558


The components of deferred income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Deferred tax expense excluding items below
 
$
49,793

 
$
27,516

 
$
27,995

Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
 
(4,346
)
 
(1,676
)
 
(837
)
Tax expense allocated to other comprehensive income
 
(51
)
 
(51
)
 
(51
)
Deferred tax expense
 
$
45,396

 
$
25,789

 
$
27,107

Schedule of Deferred Tax Assets and Liabilities 
The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:
(Thousands of Dollars)
 
2014
 
2013
Deferred tax liabilities:
 
 
 
 
Difference between book and tax bases of property
 
$
319,265

 
$
287,121

Regulatory assets
 
72,670

 
57,296

Employee benefits
 
18,691

 
16,953

Other
 
14,453

 
10,193

Total deferred tax liabilities
 
$
425,079

 
$
371,563

Deferred tax assets:
 
 
 
 
Environmental remediation
 
43,207

 
43,501

NOL carryforward
 
18,283

 
17,384

Regulatory liabilities
 
10,460

 
6,205

Deferred investment tax credits
 
5,628

 
5,976

Tax credit carryforward
 
4,515

 
4,440

Other
 
3,007

 
3,871

Total deferred tax assets
 
$
85,100

 
$
81,377

Net deferred tax liability
 
$
339,979

 
$
290,186

Benefit Plans and Other Postretirement Benefits (Tables)
Projected Benefit Payments for the Pension and Postretirement Benefit Plans 
The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans:
(Thousands of Dollars)
 
Projected Pension
Benefit Payments
 
Gross Projected
Postretirement
Health Care
Benefit Payments
 
Expected Medicare
Part D Subsidies
 
Net Projected
Postretirement
Health Care
Benefit Payments
2015
 
$
12,517

 
$
1,547

 
$
13

 
$
1,534

2016
 
13,288

 
1,473

 
11

 
1,462

2017
 
13,164

 
1,397

 
9

 
1,388

2018
 
12,564

 
1,352

 
8

 
1,344

2019
 
13,289

 
1,311

 
7

 
1,304

2020-2024
 
65,118

 
5,816

 
30

 
5,786

Contributions to Multiemployer Plans 
Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2014, 2013 and 2012. There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Multiemployer plan contributions:
 
 
 
 
 
 
Pension
 
$
156

 
$
130

 
$
163

Total
 
$
156

 
$
130

 
$
163

Target Asset Allocations and Plan Assets Measured at Fair Value 
The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2014
 
2013
Domestic and international equity securities
 
39
%
 
31
%
Long-duration fixed income and interest rate swap securities
 
23

 
29

Short-to-intermediate term fixed income securities
 
14

 
16

Alternative investments
 
22

 
22

Cash
 
2

 
2

Total
 
100
%
 
100
%
The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:
 
 
Dec. 31, 2014
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
7,910

 
$
—

 
$
—

 
$
7,910

Derivatives
 
—

 
28

 
—

 
28

Government securities
 
—

 
16,084

 
—

 
16,084

Corporate bonds
 
—

 
13,231

 
—

 
13,231

Asset-backed securities
 
—

 
162

 
—

 
162

Mortgage-backed securities
 
—

 
475

 
—

 
475

Common stock
 
4,424

 
—

 
—

 
4,424

Private equity investments
 
—

 
—

 
7,078

 
7,078

Commingled funds
 
—

 
81,806

 
—

 
81,806

Real estate
 
—

 
—

 
2,510

 
2,510

Securities lending collateral obligation and other
 
—

 
(995
)
 
—

 
(995
)
Total
 
$
12,334

 
$
110,791

 
$
9,588

 
$
132,713

 
 
Dec. 31, 2013
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
4,332

 
$
—

 
$
—

 
$
4,332

Derivatives
 
—

 
937

 
—

 
937

Government securities
 
—

 
6,711

 
—

 
6,711

Corporate bonds
 
—

 
24,955

 
—

 
24,955

Asset-backed securities
 
—

 
307

 
—

 
307

Mortgage-backed securities
 
—

 
684

 
—

 
684

Common stock
 
4,533

 
—

 
—

 
4,533

Private equity investments
 
—

 
—

 
7,502

 
7,502

Commingled funds
 
—

 
84,364

 
—

 
84,364

Real estate
 
—

 
—

 
2,299

 
2,299

Securities lending collateral obligation and other
 
—

 
311

 
—

 
311

Total
 
$
8,865

 
$
118,269

 
$
9,801

 
$
136,935

Changes in Level 3 Plan Assets 
The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:
(Thousands of Dollars)
 
Jan. 1, 2014
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfer Out
of Level 3
 
Dec. 31, 2014
Private equity investments
 
$
7,502

 
$
1,197

 
$
(1,197
)
 
$
(424
)
 
$
—

 
$
7,078

Real estate
 
2,299

 
166

 
(234
)
 
279

 
—

 
2,510

Total
 
$
9,801

 
$
1,363

 
$
(1,431
)
 
$
(145
)
 
$
—

 
$
9,588


(Thousands of Dollars)
 
Jan. 1, 2013
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3 (a)
 
Dec. 31, 2013
Asset-backed securities
 
$
749

 
$
—

 
$
—

 
$
—

 
$
(749
)
 
$
—

Mortgage-backed securities
 
2,128

 
—

 
—

 
—

 
(2,128
)
 
—

Private equity investments
 
8,545

 
1,083

 
(1,960
)
 
(166
)
 
—

 
7,502

Real estate
 
3,472

 
(129
)
 
247

 
450

 
(1,741
)
 
2,299

Total
 
$
14,894

 
$
954

 
$
(1,713
)
 
$
284

 
$
(4,618
)
 
$
9,801



(a) 
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
(Thousands of Dollars)
 
Jan. 1, 2012
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3
 
Dec. 31, 2012
Asset-backed securities
 
$
1,578

 
$
197

 
$
(273
)
 
$
(753
)
 
$
—

 
$
749

Mortgage-backed securities
 
3,781

 
93

 
(112
)
 
(1,634
)
 
—

 
2,128

Private equity investments
 
8,440

 
945

 
(1,197
)
 
357

 
—

 
8,545

Real estate
 
2,008

 
1

 
328

 
1,135

 
—

 
3,472

Total
 
$
15,807

 
$
1,236

 
$
(1,254
)
 
$
(895
)
 
$
—

 
$
14,894

Change in Projected Benefit Obligation 
Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2014
 
2013
Accumulated Benefit Obligation at Dec. 31
 
$
153,590

 
$
153,894

 
 
 
 
 
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
163,930

 
$
179,995

Service cost
 
4,527

 
5,682

Interest cost
 
7,257

 
6,924

Plan amendments
 
—

 
(1,109
)
Actuarial loss (gain)
 
9,126

 
(11,097
)
Benefit payments
 
(19,171
)
 
(16,465
)
Obligation at Dec. 31
 
$
165,669

 
$
163,930

Change in Fair Value of Plan Assets 
(Thousands of Dollars)
 
2014
 
2013
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
136,935

 
$
136,546

Actual return on plan assets
 
6,916

 
5,525

Employer contributions
 
8,033

 
11,329

Benefit payments
 
(19,171
)
 
(16,465
)
Fair value of plan assets at Dec. 31
 
$
132,713

 
$
136,935

Funded Status of Plans 
(Thousands of Dollars)
 
2014
 
2013
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status (a)
 
$
(32,956
)
 
$
(26,995
)

(a) 
Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost 
(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
90,007

 
$
84,773

Prior service cost
 
667

 
778

Total
 
$
90,674

 
$
85,551

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates 
(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
 
 
 
 
Current regulatory assets
 
$
6,728

 
$
7,631

Noncurrent regulatory assets
 
83,946

 
77,920

Total
 
$
90,674

 
$
85,551

Schedule of Assumptions Used 
Measurement date
 
Dec. 31, 2014
 
Dec. 31, 2013
 
 
2014
 
2013
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.11
%
 
4.75
%
Expected average long-term increase in compensation level
 
3.75

 
3.75

Mortality table
 
RP 2014

 
RP 2000

 
 
2014
 
2013
 
2012
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.75
%
 
4.00
%
 
5.00
%
Expected average long-term increase in compensation level
 
3.75

 
3.75

 
4.00

Expected average long-term rate of return on assets
 
7.25

 
7.25

 
7.50

Components of Net Periodic Benefit Costs 
Benefit Costs — The components of NSP-Wisconsin’s net periodic pension cost were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Service cost
 
$
4,527

 
$
5,682

 
$
4,568

Interest cost
 
7,257

 
6,924

 
7,765

Expected return on plan assets
 
(9,642
)
 
(9,995
)
 
(10,489
)
Amortization of prior service cost
 
111

 
417

 
1,771

Amortization of net loss
 
6,617

 
7,924

 
6,004

Net periodic pension cost
 
$
8,870

 
$
10,952

 
$
9,619

Target Asset Allocations and Plan Assets Measured at Fair Value 
The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2014
 
2013
Domestic and international equity securities
 
25
%
 
41
%
Short-to-intermediate fixed income securities
 
57

 
40

Alternative investments
 
13

 
13

Cash
 
5

 
6

Total
 
100
%
 
100
%
The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:
 
 
Dec. 31, 2014
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
28

 
$
—

 
$
—

 
$
28

Government securities
 
—

 
52

 
—

 
52

Insurance contracts
 
—

 
54

 
—

 
54

Corporate bonds
 
—

 
59

 
—

 
59

Asset-backed securities
 
—

 
4

 
—

 
4

Mortgage-backed securities
 
—

 
12

 
—

 
12

Commingled funds
 
—

 
304

 
—

 
304

Other
 
—

 
(1
)
 
—

 
(1
)
Total
 
$
28

 
$
484

 
$
—

 
$
512

 
 
Dec. 31, 2013
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash equivalents
 
$
31

 
$
—

 
$
—

 
$
31

Derivatives
 
—

 
(2
)
 
—

 
(2
)
Government securities
 
—

 
89

 
—

 
89

Insurance contracts
 
—

 
80

 
—

 
80

Corporate bonds
 
—

 
79

 
—

 
79

Asset-backed securities
 
—

 
5

 
—

 
5

Mortgage-backed securities
 
—

 
37

 
—

 
37

Commingled funds
 
—

 
452

 
—

 
452

Other
 
—

 
(25
)
 
—

 
(25
)
Total
 
$
31

 
$
715

 
$
—

 
$
746

Changes in Level 3 Plan Assets 
For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:
(Thousands of Dollars)
 
Jan. 1, 2013
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3 (a)
 
Dec. 31, 2013
Asset-backed securities
 
$
1

 
$
—

 
$
—

 
$
—

 
$
(1
)
 
$
—

Mortgage-backed securities
 
54

 
—

 
—

 
—

 
(54
)
 
—

Total
 
$
55

 
$
—

 
$
—

 
$
—

 
$
(55
)
 
$
—



(a) 
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
(Thousands of Dollars)
 
Jan. 1, 2012
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Purchases,
Issuances and
Settlements, Net
 
Transfers Out of Level 3
 
Dec. 31, 2012
Asset-backed securities
 
$
14

 
$
—

 
$
3

 
$
(16
)
 
$
—

 
$
1

Mortgage-backed securities
 
48

 
(1
)
 
6

 
1

 
—

 
54

Total
 
$
62

 
$
(1
)
 
$
9

 
$
(15
)
 
$
—

 
$
55

Change in Projected Benefit Obligation 
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2014
 
2013
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
17,153

 
$
19,432

Service cost
 
35

 
25

Interest cost
 
791

 
760

Medicare subsidy reimbursements
 
2

 
31

Plan participants’ contributions
 
284

 
621

Actuarial gain
 
(38
)
 
(1,724
)
Benefit payments
 
(1,459
)
 
(1,992
)
Obligation at Dec. 31
 
$
16,768

 
$
17,153

Change in Fair Value of Plan Assets 
(Thousands of Dollars)
 
2014
 
2013
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
746

 
$
647

Actual return on plan assets
 
(15
)
 
(13
)
Plan participants’ contributions
 
284

 
621

Employer contributions
 
956

 
1,483

Benefit payments
 
(1,459
)
 
(1,992
)
Fair value of plan assets at Dec. 31
 
$
512

 
$
746

Funded Status of Plans 
(Thousands of Dollars)
 
2014
 
2013
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status
 
$
(16,256
)
 
$
(16,407
)
Current liabilities
 
(1,022
)
 
(718
)
Noncurrent liabilities
 
(15,234
)
 
(15,689
)
Net postretirement amounts recognized on consolidated balance sheets
 
$
(16,256
)
 
$
(16,407
)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost 
(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
10,461

 
$
11,098

Prior service credit
 
(2,836
)
 
(3,187
)
Total
 
$
7,625

 
$
7,911

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates 
(Thousands of Dollars)
 
2014
 
2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
 
 
 
 
Current regulatory assets
 
$
95

 
$
570

Noncurrent regulatory assets
 
7,530

 
7,341

Total
 
$
7,625

 
$
7,911

Schedule of Assumptions Used 
 
 
2014
 
2013
 
2012
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.82
%
 
4.10
%
 
5.00
%
Expected average long-term rate of return on assets
 
7.08

 
7.11

 
6.75

Measurement date
 
Dec. 31, 2014
 
Dec. 31, 2013
 
 
2014
 
2013
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.08
%
 
4.82
%
Mortality table
 
RP 2014

 
RP 2000

Health care costs trend rate — initial
 
6.50
%
 
7.00
%
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate 
A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin:
 
 
One-Percentage Point
(Thousands of Dollars)
 
Increase
 
Decrease
APBO
 
$
1,722

 
$
(1,450
)
Service and interest components
 
98

 
(80
)
Components of Net Periodic Benefit Costs 
Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit costs were:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Service cost
 
$
35

 
$
25

 
$
20

Interest cost
 
791

 
760

 
1,075

Expected return on plan assets
 
(52
)
 
(42
)
 
(50
)
Amortization of transition obligation
 
—

 
1

 
171

Amortization of prior service credit
 
(351
)
 
(351
)
 
(14
)
Amortization of net loss
 
666

 
963

 
486

Net periodic postretirement benefit cost
 
$
1,089

 
$
1,356

 
$
1,688

Other Income, Net (Tables)
Other Income, Net
Other income, net for the years ended Dec. 31 consisted of the following:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Interest income
 
$
368

 
$
538

 
$
736

Other nonoperating income
 
321

 
152

 
129

Insurance policy expense
 
(409
)
 
(427
)
 
(389
)
Other nonoperating expense
 
(10
)
 
(10
)
 
—

Other income, net
 
$
270

 
$
253

 
$
476

Fair Value of Financial Assets and Liabilities (Tables)
Gross Notional Amounts of Commodity Forwards and Options 
The following table details the gross notional amounts of commodity options at Dec. 31:
(Amounts in Thousands) (a)(b)
 
2014
 
2013
MMBtu of natural gas
 
18

 
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.
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss 
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
 
$
(361
)
 
$
(437
)
 
$
(514
)
After-tax net realized losses on derivative transactions reclassified into earnings
 
76

 
76

 
77

Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
 
$
(285
)
 
$
(361
)
 
$
(437
)
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level 
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:
 
 
Dec. 31, 2014
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (b)
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
52

 
$
—

 
$
52

 
$
—

 
$
52

 
 
Dec. 31, 2013
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (c)
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 Dec. 31, 2014 and 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 other current assets balance of $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.
(c) 
Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.
Carrying Amount and Fair Value of Long-term Debt 
As of Dec. 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
 
2014
 
2013
(Thousands of Dollars)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt, including current portion
 
$
568,291

 
$
670,665

 
$
468,597

 
$
518,269

Commitments and Contingencies (Tables)
Estimated Minimum Purchases Under Fuel Contracts 
The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2014 are as follows:
(Millions of dollars)
 
Coal
 
Natural gas
supply
 
Natural gas
storage and
transportation
2015
 
$
6.6

 
$
12.4

 
$
13.2

2016
 
0.8

 
0.3

 
13.1

2017
 
0.9

 
0.2

 
10.4

2018
 
0.8

 
—

 
4.7

2019
 
0.8

 
—

 
3.1

Thereafter
 
3.3

 
—

 
13.5

Total (a)
 
$
13.2

 
$
12.9

 
$
58.0


(a) 
Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.
Future Commitments Under Operating Leases 
Future commitments under operating leases are:
(Millions of Dollars)
 
 
2015
 
$
0.9

2016
 
0.9

2017
 
1.0

2018
 
1.0

2019
 
1.0

Thereafter
 
7.9

Total
 
$
12.7

Low-income Housing Limited Partnerships 
Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following:
(Thousands of Dollars)
 
Dec. 31, 2014
 
Dec. 31, 2013
Current assets
 
$
246

 
$
223

Property, plant and equipment, net
 
2,278

 
2,427

Other noncurrent assets
 
122

 
112

Total assets
 
$
2,646

 
$
2,762

 
 
 
 
 
Current liabilities
 
$
1,349

 
$
233

Mortgages and other long-term debt payable
 
486

 
1,687

Other noncurrent liabilities
 
48

 
42

Total liabilities
 
$
1,883

 
$
1,962

Guarantee Issued and Outstanding 
The following table presents the guarantee issued and outstanding for NSP-Wisconsin:
(Millions of Dollars)
 
Guarantee
Amount
 
Current
Exposure
 
Term or
Expiration Date
 
Triggering
Event
Guarantee of customer loans for the Farm Rewiring Program
 
$
1.0

 
$
0.2

 
2018
 
(a) 

(a) 
The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Asset Retirement Obligations 
A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2014 and 2013 is as follows:
(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2014
 
Liabilities Recognized
 
Accretion
 
Cash Flow Revisions
 
Ending Balance
Dec. 31, 2014 (a)
Electric plant
 
 
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
2,005

 
$
—

 
$
44

 
$
—

 
$
2,049

Steam and other production ash containment
 
361

 
—

 
13

 
—

 
374

Electric distribution
 
36

 
—

 
1

 
—

 
37

Other
 
289

 
113

 
10

 
—

 
412

Natural gas plant
 
 
 
 
 
 
 
 
 
 
Gas distribution
 
75

 
402

 
5

 
5,645

 
6,127

Common and other property
 
 
 
 
 
 
 
 
 
 
Common miscellaneous
 
87

 
—

 
3

 
1

 
91

Total liability (b)
 
$
2,853

 
$
515

 
$
76

 
$
5,646

 
$
9,090

(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2013
 
Liabilities Recognized
 
Accretion
 
Cash Flow Revisions
 
Ending Balance
Dec. 31, 2013 (a)
Electric plant
 
 
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
1,962

 
$
—

 
$
43

 
$
—

 
$
2,005

Steam and other production ash containment
 
125

 
—

 
12

 
224

 
361

Electric distribution
 
13

 
—

 
1

 
22

 
36

Other
 
826

 
—

 
20

 
(557
)
 
289

Natural gas plant
 
 
 
 
 
 
 
 
 
 
Gas distribution
 
75

 
—

 
5

 
(5
)
 
75

Common and other property
 
 
 
 
 
 
 
 
 
 
Common miscellaneous
 
35

 
—

 
3

 
49

 
87

Total liability (b)
 
$
3,036

 
$
—

 
$
84

 
$
(267
)
 
$
2,853


(a) 
There were no ARO liabilities settled during the years ended Dec. 31, 2014 or 2013.
(b) 
Included in the other long-term liabilities balance in the consolidated balance sheets.
Regulatory Assets and Liabilities (Tables)
Regulatory Assets 
The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2014 and 2013 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2014
 
Dec. 31, 2013
Regulatory Assets
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Environmental remediation costs
 
1, 11
 
Various
 
$
4,376

 
$
147,793

 
$
4,376

 
$
117,684

Pension and retiree medical obligations (a)
 
7
 
Various
 
6,837

 
91,601

 
8,202

 
85,220

Recoverable deferred taxes on AFUDC recorded in plant
 
1
 
Plant lives
 
—

 
16,711

 
—

 
12,679

Losses on reacquired debt
 
4
 
Term of related debt
 
801

 
4,936

 
801

 
5,737

State commission adjustments
 
1
 
Plant lives
 
488

 
11,650

 
410

 
9,355

Conservation programs
 
1
 
Less than one year
 
—

 
—

 
404

 
—

Deferred income tax adjustment
 
1, 6
 
Typically plant lives
 
—

 
1,514

 
—

 
1,763

Recoverable purchased natural gas and electric energy costs
 
 
 
Less than one year
 
6,946

 
—

 
673

 
—

Monticello EPU
 

 
Pending rate cases
 
—

 
5,237

 
—

 
—

Other
 
 
 
Various
 
588

 
1,251

 
—

 
755

Total regulatory assets
 
 
 
 
 
$
20,036

 
$
280,693

 
$
14,866

 
$
233,193


(a) 
Includes the non-qualified pension plan.
Regulatory Liabilities 
The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2014 and 2013 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2014
 
Dec. 31, 2013
Regulatory Liabilities
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Plant removal costs
 
11
 
Plant lives
 
$
—

 
$
123,105

 
$
—

 
$
116,293

DOE settlement
 
11
 
Less than one year
 
4,931

 
—

 
6,814

 
—

Investment tax credit deferrals
 
1, 6
 
Various
 
—

 
9,397

 
—

 
9,976

Conservation programs
 
1
 
Less than one year
 
1,010

 
—

 
1,187

 
—

Deferred electric production and natural gas costs
 
1
 
Less than one year
 
—

 
—

 
1,542

 
—

Excess depreciation reserve
 
 
 
Various
 
10,999

 
—

 
—

 
—

Other
 
 
 
Various
 
—

 
172

 
174

 
155

Total regulatory liabilities
 
 
 
 
 
$
16,940

 
$
132,674

 
$
9,717

 
$
126,424

Other Comprehensive Income (Tables)
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax 
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2014 and 2013 were as follows:
 
 
Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)
 
Year Ended Dec. 31, 2014
 
Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1
 
$
(361
)
 
$
(437
)
Losses reclassified from net accumulated other comprehensive loss
 
76

 
76

Net current period OCI
 
76

 
76

Accumulated other comprehensive loss at Dec. 31
 
$
(285
)
 
$
(361
)
Reclassifications out of Accumulated Other Comprehensive Loss 
Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:
 
 
Amounts Reclassified from Accumulated
Other Comprehensive Loss
 
(Thousands of Dollars)
 
Year Ended Dec. 31, 2014
 
Year Ended Dec. 31, 2013
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
127

(a) 
$
127

(a) 
Total, pre-tax
 
127

 
127

 
Tax benefit
 
(51
)
 
(51
)
 
Total amounts reclassified, net of tax
 
$
76

 
$
76

 

(a) 
Included in interest charges.
Segments and Related Information (Tables)
Results from Operations by Reportable Segment
(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2014
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
829,748

 
$
169,629

 
$
1,085

 
$
—

 
$
1,000,462

Intersegment revenues
 
497

 
4,885

 
—

 
(5,382
)
 
—

Total revenues
 
$
830,245

 
$
174,514

 
$
1,085

 
$
(5,382
)
 
$
1,000,462

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
65,978

 
$
13,501

 
$
175

 
$
—

 
$
79,654

Interest charges and financing costs
 
23,448

 
2,358

 
107

 
—

 
25,913

Income tax expense (benefit)
 
39,621

 
5,993

 
(3,211
)
 
—

 
42,403

Net Income
 
59,060

 
8,714

 
2,868

 
—

 
70,642

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2013
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
789,168

 
$
132,867

 
$
1,003

 
$
—

 
$
923,038

Intersegment revenues
 
350

 
1,967

 
—

 
(2,317
)
 
—

Total revenues
 
$
789,518

 
$
134,834

 
$
1,003

 
$
(2,317
)
 
$
923,038

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
64,237

 
$
12,485

 
$
175

 
$
—

 
$
76,897

Interest charges and financing costs
 
22,966

 
2,749

 
101

 
—

 
25,816

Income tax expense (benefit)
 
33,691

 
4,623

 
(1,905
)
 
—

 
36,409

Net Income
 
51,334

 
6,501

 
1,633

 
—

 
59,468

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2012
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
757,565

 
$
103,100

 
$
1,177

 
$
—

 
$
861,842

Intersegment revenues
 
355

 
727

 
—

 
(1,082
)
 
—

Total revenues
 
$
757,920

 
$
103,827

 
$
1,177

 
$
(1,082
)
 
$
861,842

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
59,768

 
$
9,251

 
$
215

 
$
—

 
$
69,234

Interest charges and financing costs
 
20,303

 
2,554

 
80

 
—

 
22,937

Income tax expense
 
27,164

 
2,113

 
281

 
—

 
29,558

Net Income
 
45,377

 
3,094

 
1,480

 
—

 
49,951


(a) 
Operating revenues include $145 million, $137 million and $125 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012 respectively. See Note 15 for further discussion of related party transactions by operating segment.
Related Party Transactions (Tables)
Related Party Transactions
The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Thousands of Dollars)
 
2014
 
2013
 
2012
Operating revenues:
 
 
 
 
 
 
Electric
 
$
145,102

 
$
136,917

 
$
125,344

Operating expenses:
 
 
 
 
 
 
Purchased power (a)
 
430,666

 
416,173

 
405,016

Transmission expense
 
43,876

 
42,460

 
44,942

Natural gas purchased for resale
 
90

 
97

 
116

Other operating expenses — paid to Xcel Energy Services Inc.
 
84,224

 
61,531

 
54,137

Interest expense
 
30

 
22

 
22


(a) 
Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

Accounts receivable and payable with affiliates at Dec. 31 were:
 
 
2014
 
2013
(Thousands of Dollars)
 
Accounts
Receivable
 
Accounts
Payable
 
Accounts
Receivable
 
Accounts
Payable
NSP-Minnesota
 
$
—

 
$
17,333

 
$
—

 
$
18,584

PSCo
 
—

 
22

 
—

 
8

SPS
 
31

 
—

 
26

 
—

Other subsidiaries of Xcel Energy Inc.
 
—

 
9,169

 
1,569

 
6,394

 
 
$
31

 
$
26,524

 
$
1,595

 
$
24,986

Summarized Quarterly Financial Data (Unaudited) (Tables)
Summarized Quarterly Financial Data (Unaudited)
 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2014
 
June 30, 2014
 
Sept. 30, 2014
 
Dec. 31, 2014
Operating revenues
 
$
285,142

 
$
228,114

 
$
231,046

 
$
256,160

Operating income
 
42,571

 
23,730

 
37,540

 
27,787

Net income
 
24,235

 
12,022

 
20,030

 
14,355

 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2013
 
June 30, 2013
 
Sept. 30, 2013
 
Dec. 31, 2013
Operating revenues
 
$
241,415

 
$
210,175

 
$
231,060

 
$
240,388

Operating income
 
37,401

 
22,466

 
40,769

 
16,545

Net income
 
19,685

 
10,544

 
22,013

 
7,225

Summary of Significant Accounting Policies (Details)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Property, Plant and Equipment [Abstract]
 
 
 
Depreciation expense expressed as a percentage of average depreciable property
3.30% 
3.50% 
3.50% 
Cash and Cash Equivalents [Abstract]
 
 
 
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents
3 months 
 
 
Selected Balance Sheet Data, Accounts Receivable (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Accounts Receivable, Net
 
 
Accounts receivable
$ 66,217 
$ 64,180 
Less allowance for bad debts
(5,821)
(4,911)
Accounts receivable, net
60,396 1
59,269 1
Accounts receivable from affiliates, net
$ 31 
$ 1,595 
Selected Balance Sheet Data, Inventory (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Public Utilities, Inventory [Line Items]
 
 
Inventories
$ 24,685 
$ 21,475 
Materials and supplies
 
 
Public Utilities, Inventory [Line Items]
 
 
Inventories
6,494 
6,437 
Fuel
 
 
Public Utilities, Inventory [Line Items]
 
 
Inventories
6,654 
5,915 
Natural gas
 
 
Public Utilities, Inventory [Line Items]
 
 
Inventories
$ 11,537 
$ 9,123 
Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
 
 
Property, Plant and Equipment, Gross
$ 2,674,485 
$ 2,390,241 
Less accumulated depreciation
(1,000,204)
(947,462)
Property, plant and equipment, net
1,674,281 
1,442,779 
Electric plant
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
Property, Plant and Equipment, Gross
2,061,669 
1,913,354 
Natural gas plant
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
Property, Plant and Equipment, Gross
255,465 
236,047 
Common and other property
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
Property, Plant and Equipment, Gross
125,938 
112,886 
CWIP
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
Property, Plant and Equipment, Gross
$ 231,413 
$ 127,954 
Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Short-term Debt [Line Items]
 
 
 
 
Amount outstanding at period end
$ 78,000,000 
$ 78,000,000 
$ 68,000,000 
 
Commercial Paper
 
 
 
 
Short-term Debt [Line Items]
 
 
 
 
Borrowing limit
150,000,000 
150,000,000 
150,000,000 
150,000,000 
Amount outstanding at period end
78,000,000 
78,000,000 
68,000,000 
39,000,000 
Average amount outstanding
34,000,000 
46,000,000 
20,000,000 
61,000,000 
Maximum amount outstanding
$ 80,000,000 
$ 101,000,000 
$ 71,000,000 
$ 116,000,000 
Weighted average interest rate, computed on a daily basis (percentage)
0.37% 
0.27% 
0.31% 
0.39% 
Weighted average interest rate at period end (percentage)
0.55% 
0.55% 
0.27% 
0.40% 
Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2014
Letter of Credit
Dec. 31, 2013
Letter of Credit
Dec. 31, 2014
Letter of Credit
Line of Credit Facility [Line Items]
 
 
 
 
 
Term of letters of credit (in years)
 
 
 
 
1 year 
Amount outstanding at period end
$ 78,000 
$ 68,000 
$ 0 
$ 0 
 
Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)
1 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Oct. 31, 2014
Credit Facility
Dec. 31, 2014
Credit Facility
Dec. 31, 2014
Maximum
Credit Facility
Dec. 31, 2014
Minimum
Credit Facility
Dec. 31, 2014
Eurodollar
Maximum
Credit Facility
Dec. 31, 2014
Eurodollar
Minimum
Credit Facility
Line of Credit Facility [Line Items]
 
 
 
 
 
 
 
 
Credit Facility
 
 
 
$ 150,000,000 1
 
 
 
 
Drawn
 
 
 
78,000,000 2
 
 
 
 
Available
 
 
 
72,000,000 
 
 
 
 
Direct advances on the credit facility outstanding
0 
0 
 
 
 
 
 
 
Debt Instrument, Term
 
 
5 years 
 
 
 
 
 
Line of Credit Facility, Initiation Date
 
 
Oct. 14, 2014 
 
 
 
 
 
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed
65.00% 
 
 
 
 
 
 
 
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval
 
 
 
1 year 
 
 
 
 
Line Of Credit Facility Debt To Total Capitalization Ratio
48.00% 
47.00% 
 
 
 
 
 
 
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions
15.00% 
 
 
 
 
 
 
 
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions
$ 75,000,000 
 
 
 
 
 
 
 
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings
 
 
 
 
 
 
 
0.875% 
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings
 
 
 
 
 
 
1.75% 
 
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit
 
 
 
 
 
0.075% 
 
 
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit
 
 
 
 
0.275% 
 
 
 
Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangements and Other Short-Term Borrowings (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Short-term Debt [Line Items]
 
 
Notes payable to affiliates
$ 500 
$ 470 
Notes Payable, Other Payables
 
 
Short-term Debt [Line Items]
 
 
Notes payable to affiliates
$ 500 
$ 500 
Weighted average interest rate at period end (percentage)
0.51% 
0.24% 
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (USD $)
1 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Jun. 30, 2014
First Mortgage Bonds
Series Due June 15, 2024
Dec. 31, 2014
First Mortgage Bonds
Series Due June 15, 2024
Dec. 31, 2014
First Mortgage Bonds
Series Due Oct. 1, 2018 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
Face Amount
 
 
$ 100,000,000 
 
 
Interest Rate, Stated Percentage
 
 
3.30% 
3.30% 
5.25% 
Maturity Date
 
 
Jun. 15, 2024 
Jun. 15, 2024 
Oct. 01, 2018 
Long-term Debt, Maturities, Repayments of Principal in Year Four
 
 
 
 
150,000,000 
Deferred Finance Costs, Noncurrent, Net
4,300,000 
3,500,000 
 
 
 
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met
33,300,000 
 
 
 
 
Minimum calendar year average equity to total capitalization ratio authorized by state commission
52.50% 
 
 
 
 
Calendar year average equity to total capitalization ratio
52.80% 
 
 
 
 
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions
$ 8,300,000 
 
 
 
 
Joint Ownership of Transmission Facilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Jointly Owned Utility Plant [Abstract]
 
Plant in service
$ 26,434 
Accumulated depreciation
8,082 
Construction work in progress
113,754 
CapX2020 Transmission |
Electric Transmission
 
Jointly Owned Utility Plant [Abstract]
 
Plant in service
26,434 
Accumulated depreciation
8,082 
Construction work in progress
103,940 
Ownership % (in hundredths)
80.70% 
La Crosse, Wis. to Madison, Wis. |
Electric Transmission
 
Jointly Owned Utility Plant [Abstract]
 
Plant in service
0 
Accumulated depreciation
0 
Construction work in progress
$ 9,814 
Ownership % (in hundredths)
50.00% 
Income Taxes (Details) (USD $)
12 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Sep. 30, 2012
Internal Revenue Service (IRS)
Dec. 31, 2014
Internal Revenue Service (IRS)
Dec. 31, 2013
Internal Revenue Service (IRS)
Dec. 31, 2014
State and Local Jurisdiction
Dec. 31, 2013
State and Local Jurisdiction
Tax Increase Prevention Act of 2014 [Abstract]
 
 
 
 
 
 
 
 
Bonus depreciation rate
50.00% 
50.00% 
 
 
 
 
 
 
Number of years bonus depreciation was extended
1 year 
1 year 
 
 
 
 
 
 
American Taxpayer Relief Act of 2012 [Abstract]
 
 
 
 
 
 
 
 
Original top tax rate for dividends
 
15.00% 
 
 
 
 
 
 
New top tax rate for dividends
 
20.00% 
 
 
 
 
 
 
Bonus depreciation rate
50.00% 
50.00% 
 
 
 
 
 
 
Number of years bonus depreciation was extended
1 year 
1 year 
 
 
 
 
 
 
Tax Audits [Abstract]
 
 
 
 
 
 
 
 
Year(s) no longer subject to audit as statute of limitations has expired
 
 
 
 
2008 
 
 
 
Earliest year subject to examination
 
 
 
 
2009 
 
2010 
 
Year(s) under examination
 
 
 
2010 and 2011 
 
 
2009 through 2011 
 
Tax Adjustments, Settlements, and Unusual Provisions
 
 
 
 
$ 12,000,000 
 
 
 
Operating Loss Carryforwards
 
 
 
 
48,500,000 
46,800,000 
3,400,000 
6,300,000 
Tax Credit Carryforward, Amount
 
 
 
 
4,500,000 
4,400,000 
 
 
Carryforward expiration date range, low
 
 
 
 
2021 
 
2022 
 
Carryforward expiration date range, high
 
 
 
 
2034 
 
2031 
 
Unrecognized Tax Benefits [Abstract]
 
 
 
 
 
 
 
 
Unrecognized tax benefit — Permanent tax positions
100,000 
100,000 
 
 
 
 
 
 
Unrecognized tax benefit — Temporary tax positions
2,900,000 
1,400,000 
 
 
 
 
 
 
Total unrecognized tax benefit
3,000,000 
1,500,000 
1,300,000 
 
 
 
 
 
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
 
 
 
 
 
 
 
 
Balance at Jan. 1
1,500,000 
1,300,000 
1,500,000 
 
 
 
 
 
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions
1,900,000 
700,000 
500,000 
 
 
 
 
 
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions
(200,000)
0 
(200,000)
 
 
 
 
 
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions
100,000 
500,000 
300,000 
 
 
 
 
 
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions
(200,000)
0 
(800,000)
 
 
 
 
 
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities
(100,000)
(1,000,000)
0 
 
 
 
 
 
Balance at Dec. 31
3,000,000 
1,500,000 
1,300,000 
 
 
 
 
 
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
 
 
 
 
 
 
 
 
NOL and tax credit carryforwards
(900,000)
(400,000)
 
 
 
 
 
 
Amounts accrued for penalties related to unrecognized tax benefits
0 
0 
0 
 
 
 
 
 
Effective Income Tax Rate Reconciliation, Percent [Abstract]
 
 
 
 
 
 
 
 
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent
35.00% 
35.00% 
35.00% 
 
 
 
 
 
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent
4.90% 
5.00% 
3.40% 
 
 
 
 
 
Effective Income Tax Rate Reconciliation, Tax Credit, Percent
(0.70%)
(0.90%)
(0.90%)
 
 
 
 
 
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items
(1.60%)
(0.90%)
(0.30%)
 
 
 
 
 
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits
0.00% 
0.00% 
0.10% 
 
 
 
 
 
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent
(0.10%)
(0.20%)
(0.10%)
 
 
 
 
 
Effective Income Tax Rate Reconciliation, Percent
37.50% 
38.00% 
37.20% 
 
 
 
 
 
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
 
 
 
 
 
 
 
 
Current Federal Tax Expense (Benefit)
(3,932,000)
5,902,000 
930,000 
 
 
 
 
 
Current State and Local Tax Expense (Benefit)
453,000 
4,628,000 
2,216,000 
 
 
 
 
 
Current Change In Unrecognized Tax Expense (Benefit)
1,013,000 
754,000 
(69,000)
 
 
 
 
 
Deferred Federal Income Tax Expense (Benefit)
38,321,000 
23,794,000 
25,089,000 
 
 
 
 
 
Deferred State and Local Income Tax Expense (Benefit)
8,042,000 
2,720,000 
1,890,000 
 
 
 
 
 
Deferred Change In Unrecognized Tax Expense (Benefit)
(967,000)
(725,000)
128,000 
 
 
 
 
 
Deferred investment tax credits
(527,000)
(664,000)
(626,000)
 
 
 
 
 
Income Tax Expense (Benefit)
42,403,000 
36,409,000 
29,558,000 
 
 
 
 
 
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
 
 
 
 
 
 
 
 
Deferred tax expense (benefit) excluding selected items
49,793,000 
27,516,000 
27,995,000 
 
 
 
 
 
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
(4,346,000)
(1,676,000)
(837,000)
 
 
 
 
 
Other Comprehensive Income (Loss), Tax
(51,000)
(51,000)
(51,000)
 
 
 
 
 
Deferred Income Tax Expense (Benefit)
45,396,000 
25,789,000 
27,107,000 
 
 
 
 
 
Deferred Tax Liabilities, Gross [Abstract]
 
 
 
 
 
 
 
 
Deferred Tax Liabilities, Property, Plant and Equipment
319,265,000 
287,121,000 
 
 
 
 
 
 
Deferred Tax Liabilities, Regulatory Assets
72,670,000 
57,296,000 
 
 
 
 
 
 
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits
18,691,000 
16,953,000 
 
 
 
 
 
 
Deferred Tax Liabilities, Other
14,453,000 
10,193,000 
 
 
 
 
 
 
Deferred Tax Liabilities, Net
425,079,000 
371,563,000 
 
 
 
 
 
 
Deferred Tax Assets, Gross [Abstract]
 
 
 
 
 
 
 
 
Deferred Tax Assets Environmental Remediation
43,207,000 
43,501,000 
 
 
 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards
18,283,000 
17,384,000 
 
 
 
 
 
 
Deferred Tax Assets Regulatory Liabilities
10,460,000 
6,205,000 
 
 
 
 
 
 
Deferred Tax Assets Deferred Investment Tax Credits
5,628,000 
5,976,000 
 
 
 
 
 
 
Deferred Tax Assets Tax credit carryforward
4,515,000 
4,440,000 
 
 
 
 
 
 
Deferred Tax Assets, Other
3,007,000 
3,871,000 
 
 
 
 
 
 
Deferred Tax Assets, Net of Valuation Allowance
85,100,000 
81,377,000 
 
 
 
 
 
 
Deferred Tax Assets, Net
$ 339,979,000 
$ 290,186,000 
 
 
 
 
 
 
Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)
Dec. 31, 2014
Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
 
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (in hundredths)
71.00% 
Number of bargaining employees receiving benefits under several collective bargaining agreements
402 
Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)
12 Months Ended
Dec. 31, 2014
Commingled funds |
Minimum
 
Defined Benefit Plan Disclosure [Line Items]
 
Notice period for investment redemption
1 day 
Commingled funds |
Maximum
 
Defined Benefit Plan Disclosure [Line Items]
 
Notice period for investment redemption
90 days 
Real estate funds |
Minimum
 
Defined Benefit Plan Disclosure [Line Items]
 
Notice period for investment redemption
45 days 
Real estate funds |
Maximum
 
Defined Benefit Plan Disclosure [Line Items]
 
Notice period for investment redemption
90 days 
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
 
 
 
Pension Benefits [Abstract]
 
 
 
Total benefit obligation
$ 800,000 
$ 600,000 
 
Pension Plans
 
 
 
Pension Benefits [Abstract]
 
 
 
Total benefit obligation
165,669,000 
163,930,000 
179,995,000 
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years)
20 years 
 
 
Expected average long-term rate of return on assets (in hundredths)
7.25% 
7.25% 
7.50% 
Expected average long-term rate of return on assets for next fiscal year (in hundredths)
7.25% 
 
 
Target Pension Asset Allocations [Abstract]
 
 
 
Target pension asset allocations (in hundredths)
100.00% 
100.00% 
 
Pension Plans |
Domestic and international equity securities
 
 
 
Target Pension Asset Allocations [Abstract]
 
 
 
Target pension asset allocations (in hundredths)
39.00% 
31.00% 
 
Pension Plans |
Long-duration fixed income and interest rate swap securities
 
 
 
Target Pension Asset Allocations [Abstract]
 
 
 
Target pension asset allocations (in hundredths)
23.00% 
29.00% 
 
Pension Plans |
Short-to-intermediate fixed income securities
 
 
 
Target Pension Asset Allocations [Abstract]
 
 
 
Target pension asset allocations (in hundredths)
14.00% 
16.00% 
 
Pension Plans |
Alternative investments
 
 
 
Target Pension Asset Allocations [Abstract]
 
 
 
Target pension asset allocations (in hundredths)
22.00% 
22.00% 
 
Pension Plans |
Cash
 
 
 
Target Pension Asset Allocations [Abstract]
 
 
 
Target pension asset allocations (in hundredths)
2.00% 
2.00% 
 
Xcel Energy Inc. |
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
 
 
 
Pension Benefits [Abstract]
 
 
 
Total benefit obligation
46,500,000 
36,500,000 
 
Net benefit cost recognized for financial reporting
$ 4,700,000 
$ 6,600,000 
 
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) (Pension Plans, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
$ 132,713 
$ 136,935 
$ 136,546 
 
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
12,334 
8,865 
 
 
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
110,791 
118,269 
 
 
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
9,588 
9,801 
14,894 
15,807 
Cash equivalents
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
7,910 
4,332 
 
 
Cash equivalents |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
7,910 
4,332 
 
 
Cash equivalents |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Cash equivalents |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Derivatives
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
28 
937 
 
 
Derivatives |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Derivatives |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
28 
937 
 
 
Derivatives |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Government securities
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
16,084 
6,711 
 
 
Government securities |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Government securities |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
16,084 
6,711 
 
 
Government securities |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Corporate bonds
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
13,231 
24,955 
 
 
Corporate bonds |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Corporate bonds |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
13,231 
24,955 
 
 
Corporate bonds |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Asset-backed securities
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
162 
307 
 
 
Asset-backed securities |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Asset-backed securities |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
162 
307 
 
 
Asset-backed securities |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
749 
1,578 
Mortgage-backed securities
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
475 
684 
 
 
Mortgage-backed securities |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Mortgage-backed securities |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
475 
684 
 
 
Mortgage-backed securities |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
2,128 
3,781 
Common stock
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
4,424 
4,533 
 
 
Common stock |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
4,424 
4,533 
 
 
Common stock |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Common stock |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Private equity investments
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
7,078 
7,502 
 
 
Private equity investments |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Private equity investments |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Private equity investments |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
7,078 
7,502 
8,545 
8,440 
Commingled funds
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
81,806 
84,364 
 
 
Commingled funds |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Commingled funds |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
81,806 
84,364 
 
 
Commingled funds |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Real estate
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
2,510 
2,299 
 
 
Real estate |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Real estate |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Real estate |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
2,510 
2,299 
3,472 
2,008 
Securities lending collateral obligation and other
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
(995)
311 
 
 
Securities lending collateral obligation and other |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Securities lending collateral obligation and other |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
(995)
311 
 
 
Securities lending collateral obligation and other |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
$ 0 
$ 0 
 
 
Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) (Pension Plans, USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Dec. 31
$ 132,713 
$ 136,935 
$ 136,546 
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
9,801 
14,894 
15,807 
Net realized gains (losses)
1,363 
954 
1,236 
Net unrealized gains (losses)
(1,431)
(1,713)
(1,254)
Purchases, issuances and settlements, net
(145)
284 
(895)
Transfers in (out) of Level 3
0 
(4,618)1
0 
Fair value of plan assets at Dec. 31
9,588 
9,801 
14,894 
Asset-backed securities
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Dec. 31
162 
307 
 
Asset-backed securities |
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
 
749 
1,578 
Net realized gains (losses)
 
0 
197 
Net unrealized gains (losses)
 
0 
(273)
Purchases, issuances and settlements, net
 
0 
(753)
Transfers in (out) of Level 3
 
(749)1
0 
Fair value of plan assets at Dec. 31
0 
0 
749 
Mortgage-backed securities
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Dec. 31
475 
684 
 
Mortgage-backed securities |
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
 
2,128 
3,781 
Net realized gains (losses)
 
0 
93 
Net unrealized gains (losses)
 
0 
(112)
Purchases, issuances and settlements, net
 
0 
(1,634)
Transfers in (out) of Level 3
 
(2,128)1
0 
Fair value of plan assets at Dec. 31
0 
0 
2,128 
Private equity investments
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Dec. 31
7,078 
7,502 
 
Private equity investments |
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
7,502 
8,545 
8,440 
Net realized gains (losses)
1,197 
1,083 
945 
Net unrealized gains (losses)
(1,197)
(1,960)
(1,197)
Purchases, issuances and settlements, net
(424)
(166)
357 
Transfers in (out) of Level 3
0 
0 1
0 
Fair value of plan assets at Dec. 31
7,078 
7,502 
8,545 
Real estate
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Dec. 31
2,510 
2,299 
 
Real estate |
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
2,299 
3,472 
2,008 
Net realized gains (losses)
166 
(129)
1 
Net unrealized gains (losses)
(234)
247 
328 
Purchases, issuances and settlements, net
279 
450 
1,135 
Transfers in (out) of Level 3
0 
(1,741)1
0 
Fair value of plan assets at Dec. 31
$ 2,510 
$ 2,299 
$ 3,472 
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (Pension Plans, USD $)
12 Months Ended 1 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Xcel Energy Inc.
Plan
Dec. 31, 2013
Xcel Energy Inc.
Plan
Dec. 31, 2012
Xcel Energy Inc.
Plan
Jan. 31, 2015
Subsequent Event
Jan. 31, 2015
Subsequent Event
Xcel Energy Inc.
Plan
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation at Dec. 31
$ 153,590,000 
$ 153,894,000 
 
 
 
 
 
 
Change in Projected Benefit Obligation [Roll Forward]
 
 
 
 
 
 
 
 
Obligation at Jan. 1
163,930,000 
179,995,000 
 
 
 
 
 
 
Service cost
4,527,000 
5,682,000 
4,568,000 
 
 
 
 
 
Interest cost
7,257,000 
6,924,000 
7,765,000 
 
 
 
 
 
Plan amendments
0 
(1,109,000)
 
 
 
 
 
 
Actuarial (gain) loss
9,126,000 
(11,097,000)
 
 
 
 
 
 
Benefit payments
(19,171,000)
(16,465,000)
 
 
 
 
 
 
Obligation at Dec. 31
165,669,000 
163,930,000 
179,995,000 
 
 
 
 
 
Change in Fair Value of Plan Assets [Roll Forward]
 
 
 
 
 
 
 
 
Fair value of plan assets at Jan. 1
136,935,000 
136,546,000 
 
 
 
 
 
 
Actual return (loss) on plan assets
6,916,000 
5,525,000 
 
 
 
 
 
 
Employer contributions
8,033,000 
11,329,000 
 
 
 
 
 
 
Benefit payments
(19,171,000)
(16,465,000)
 
 
 
 
 
 
Fair value of plan assets at Dec. 31
132,713,000 
136,935,000 
136,546,000 
 
 
 
 
 
Funded Status of Plans at Dec. 31 [Abstract]
 
 
 
 
 
 
 
 
Funded status
(32,956,000)1
(26,995,000)1
 
 
 
 
 
 
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
 
 
 
 
 
 
 
 
Net loss
90,007,000 
84,773,000 
 
 
 
 
 
 
Prior service (credit) cost
667,000 
778,000 
 
 
 
 
 
 
Total
90,674,000 
85,551,000 
 
 
 
 
 
 
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
 
 
 
 
 
 
 
 
Current regulatory assets
6,728,000 
7,631,000 
 
 
 
 
 
 
Noncurrent regulatory assets
83,946,000 
77,920,000 
 
 
 
 
 
 
Total
90,674,000 
85,551,000 
 
 
 
 
 
 
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
 
 
 
 
 
 
 
 
Measurement date
12/31/2014 
12/31/2013 
 
 
 
 
 
 
Discount rate for year-end valuation (in hundredths)
4.11% 
4.75% 
 
 
 
 
 
 
Expected average long-term increase in compensation level (in hundredths)
3.75% 
3.75% 
 
 
 
 
 
 
Mortality table
RP 2014 
RP 2000 
 
 
 
 
 
 
Cash Flows [Abstract]
 
 
 
 
 
 
 
 
Total contributions to Xcel Energy's pension plans during the period
8,000,000 
11,300,000 
12,500,000 
130,600,000 
192,400,000 
198,100,000 
4,900,000 
90,000,000 
Number of pension plans to which contributions were made
 
 
 
4 
4 
4 
 
4 
Components of Net Periodic Benefit Cost (Credit) [Abstract]
 
 
 
 
 
 
 
 
Service cost
4,527,000 
5,682,000 
4,568,000 
 
 
 
 
 
Interest cost
7,257,000 
6,924,000 
7,765,000 
 
 
 
 
 
Expected return on plan assets
(9,642,000)
(9,995,000)
(10,489,000)
 
 
 
 
 
Amortization of prior service cost (credit)
111,000 
417,000 
1,771,000 
 
 
 
 
 
Amortization of net loss
6,617,000 
7,924,000 
6,004,000 
 
 
 
 
 
Net periodic benefit cost
8,870,000 
10,952,000 
9,619,000 
 
 
 
 
 
Significant Assumptions Used to Measure Costs [Abstract]
 
 
 
 
 
 
 
 
Discount rate (in hundredths)
4.75% 
4.00% 
5.00% 
 
 
 
 
 
Expected average long-term increase in compensation level (in hundredths)
3.75% 
3.75% 
4.00% 
 
 
 
 
 
Expected average long-term rate of return on assets (in hundredths)
7.25% 
7.25% 
7.50% 
 
 
 
 
 
Allocated costs for pension plans sponsored by Xcel Energy Inc.
$ 1,700,000 
$ 2,200,000 
$ 1,800,000 
 
 
 
 
 
Expected average long-term rate of return on assets for next fiscal year (in hundredths)
7.25% 
 
 
 
 
 
 
 
Number of years fair market value of plan assets is adjusted using calculated value method (in years)
5 years 
 
 
 
 
 
 
 
Annual adjustment rate used in calculated value method (in hundredths)
20.00% 
 
 
 
 
 
 
 
Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Defined Contribution Plans [Abstract]
 
 
 
Contributions to 401(k) and other defined contribution plans
$ 1.4 
$ 1.3 
$ 1.2 
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) (Postretirement Benefit Plan)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Postretirement Health Care Benefits [Abstract]
 
 
Amortization period for unrecognized accumulated postretirement benefit obligation (in years)
20 years 
 
Target pension asset allocations (in hundredths)
100.00% 
100.00% 
Domestic and international equity securities
 
 
Postretirement Health Care Benefits [Abstract]
 
 
Target pension asset allocations (in hundredths)
25.00% 
41.00% 
Short-to-intermediate fixed income securities
 
 
Postretirement Health Care Benefits [Abstract]
 
 
Target pension asset allocations (in hundredths)
57.00% 
40.00% 
Alternative investments
 
 
Postretirement Health Care Benefits [Abstract]
 
 
Target pension asset allocations (in hundredths)
13.00% 
13.00% 
Cash
 
 
Postretirement Health Care Benefits [Abstract]
 
 
Target pension asset allocations (in hundredths)
5.00% 
6.00% 
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
$ 512 
$ 746 
$ 647 
 
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
28 
31 
 
 
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
484 
715 
 
 
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
55 
62 
Cash equivalents
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
28 
31 
 
 
Cash equivalents |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
28 
31 
 
 
Cash equivalents |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Cash equivalents |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Derivatives
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
 
(2)
 
 
Derivatives |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
 
0 
 
 
Derivatives |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
 
(2)
 
 
Derivatives |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
 
0 
 
 
Government securities
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
52 
89 
 
 
Government securities |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Government securities |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
52 
89 
 
 
Government securities |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Insurance contracts
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
54 
80 
 
 
Insurance contracts |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Insurance contracts |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
54 
80 
 
 
Insurance contracts |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Corporate bonds
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
59 
79 
 
 
Corporate bonds |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Corporate bonds |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
59 
79 
 
 
Corporate bonds |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Asset-backed securities
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
4 
5 
 
 
Asset-backed securities |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Asset-backed securities |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
4 
5 
 
 
Asset-backed securities |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
1 
14 
Mortgage-backed securities
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
12 
37 
 
 
Mortgage-backed securities |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Mortgage-backed securities |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
12 
37 
 
 
Mortgage-backed securities |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
54 
48 
Commingled funds
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
304 
452 
 
 
Commingled funds |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Commingled funds |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
304 
452 
 
 
Commingled funds |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Other
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
(1)
(25)
 
 
Other |
Level 1
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
0 
0 
 
 
Other |
Level 2
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
(1)
(25)
 
 
Other |
Level 3
 
 
 
 
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
 
 
 
 
Fair value of plan assets
$ 0 
$ 0 
 
 
Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
 
 
$ 512 
Fair value of plan assets at Dec. 31
746 
647 
512 
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
55 
62 
0 
Net realized gains (losses)
0 
(1)
 
Net unrealized gains (losses)
0 
9 
 
Purchases, issuances and settlements, net
0 
(15)
 
Transfers in (out) of Level 3
(55)1
0 
 
Fair value of plan assets at Dec. 31
0 
55 
0 
Asset-backed securities
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
 
 
4 
Fair value of plan assets at Dec. 31
5 
 
4 
Asset-backed securities |
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
1 
14 
0 
Net realized gains (losses)
0 
0 
 
Net unrealized gains (losses)
0 
3 
 
Purchases, issuances and settlements, net
0 
(16)
 
Transfers in (out) of Level 3
(1)1
0 
 
Fair value of plan assets at Dec. 31
0 
1 
0 
Mortgage-backed securities
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
 
 
12 
Fair value of plan assets at Dec. 31
37 
 
12 
Mortgage-backed securities |
Level 3
 
 
 
Changes in Level 3 Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
54 
48 
0 
Net realized gains (losses)
0 
(1)
 
Net unrealized gains (losses)
0 
6 
 
Purchases, issuances and settlements, net
0 
1 
 
Transfers in (out) of Level 3
(54)1
0 
 
Fair value of plan assets at Dec. 31
$ 0 
$ 54 
$ 0 
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Funded Status of Plans at Dec. 31 [Abstract]
 
 
 
Noncurrent liabilities
$ (51,313,000)
$ (45,708,000)
 
Postretirement Benefit Plan
 
 
 
Change in Projected Benefit Obligation [Roll Forward]
 
 
 
Obligation at Jan. 1
17,153,000 
19,432,000 
 
Service cost
35,000 
25,000 
20,000 
Interest cost
791,000 
760,000 
1,075,000 
Medicare subsidy reimbursements
2,000 
31,000 
 
Plan participants' contributions
284,000 
621,000 
 
Actuarial (gain) loss
(38,000)
(1,724,000)
 
Benefit payments
(1,459,000)
(1,992,000)
 
Obligation at Dec. 31
16,768,000 
17,153,000 
19,432,000 
Change in Fair Value of Plan Assets [Roll Forward]
 
 
 
Fair value of plan assets at Jan. 1
746,000 
647,000 
 
Actual return (loss) on plan assets
(15,000)
(13,000)
 
Plan participants' contributions
284,000 
621,000 
 
Employer contributions
956,000 
1,483,000 
 
Benefit payments
(1,459,000)
(1,992,000)
 
Fair value of plan assets at Dec. 31
512,000 
746,000 
647,000 
Funded Status of Plans at Dec. 31 [Abstract]
 
 
 
Funded status
(16,256,000)
(16,407,000)
 
Current liabilities
(1,022,000)
(718,000)
 
Noncurrent liabilities
(15,234,000)
(15,689,000)
 
Net postretirement amounts recognized on consolidated balance sheets
(16,256,000)
(16,407,000)
 
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
 
 
 
Net loss
10,461,000 
11,098,000 
 
Prior service (credit) cost
(2,836,000)
(3,187,000)
 
Total
7,625,000 
7,911,000 
 
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
 
 
 
Current regulatory assets
95,000 
570,000 
 
Noncurrent regulatory assets
7,530,000 
7,341,000 
 
Total
7,625,000 
7,911,000 
 
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
 
 
 
Measurement date
12/31/2014 
12/31/2013 
 
Discount rate for year-end valuation (in hundredths)
4.08% 
4.82% 
 
Mortality table
RP 2014 
RP 2000 
 
Health care costs trend rate - initial (in hundredths)
6.50% 
7.00% 
 
Ultimate health care trend assumption rate (in hundredths)
4.50% 
4.50% 
 
Period until ultimate trend rate is reached (in years)
4 years 
 
 
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
 
 
 
One-percent increase in APBO
1,722,000 
 
 
One-percent decrease in APBO
(1,450,000)
 
 
One-percent increase in service and interest components
98,000 
 
 
One-percent decrease in service and interest components
(80,000)
 
 
Cash Flows [Abstract]
 
 
 
Total contributions to Xcel Energy's postretirement health care plans during the year
1,000,000 
1,500,000 
1,900,000 
Expected contribution to postretirement health care plans during 2015
1,500,000 
 
 
Components of Net Periodic Benefit Cost (Credit) [Abstract]
 
 
 
Service cost
35,000 
25,000 
20,000 
Interest cost
791,000 
760,000 
1,075,000 
Expected return on plan assets
(52,000)
(42,000)
(50,000)
Amortization of transition obligation
0 
1,000 
171,000 
Amortization of prior service cost (credit)
(351,000)
(351,000)
(14,000)
Amortization of net loss
666,000 
963,000 
486,000 
Net periodic benefit cost
1,089,000 
1,356,000 
1,688,000 
Significant Assumptions Used to Measure Costs [Abstract]
 
 
 
Discount rate (in hundredths)
4.82% 
4.10% 
5.00% 
Expected average long-term rate of return on assets (in hundredths)
7.08% 
7.11% 
6.75% 
Xcel Energy Inc. |
Postretirement Benefit Plan
 
 
 
Cash Flows [Abstract]
 
 
 
Total contributions to Xcel Energy's postretirement health care plans during the year
17,100,000 
17,600,000 
47,100,000 
Expected contribution to postretirement health care plans during 2015
$ 12,800,000 
 
 
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Pension Plans
 
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
 
2015
$ 12,517 
2016
13,288 
2017
13,164 
2018
12,564 
2019
13,289 
2020-2024
65,118 
Postretirement Benefit Plan
 
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
 
2015
1,547 
2016
1,473 
2017
1,397 
2018
1,352 
2019
1,311 
2020-2024
5,816 
Expected Medicare Part D Subsidies [Abstract]
 
2015
13 
2016
11 
2017
9 
2018
8 
2019
7 
2020-2024
30 
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
 
2015
1,534 
2016
1,462 
2017
1,388 
2018
1,344 
2019
1,304 
2020-2024
$ 5,786 
Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Employer
Dec. 31, 2013
Dec. 31, 2012
Multiemployer Plans [Abstract]
 
 
 
Number of employers that must be exceeded during a given period in order for certain union workers to participate in multiemployer plans
1 
 
 
Multiemployer contributions
$ 156 
$ 130 
$ 163 
Multiemployer Pension Plans
 
 
 
Multiemployer Plans [Abstract]
 
 
 
Multiemployer contributions
$ 156 
$ 130 
$ 163 
Other Income, Net (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Other Income and Expenses [Abstract]
 
 
 
Interest income
$ 368 
$ 538 
$ 736 
Other nonoperating income
321 
152 
129 
Insurance policy expense
(409)
(427)
(389)
Other nonoperating expense
(10)
(10)
0 
Other income, net
$ 270 
$ 253 
$ 476 
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
MMBTU
Dec. 31, 2013
MMBTU
Interest Rate [Member]
 
 
Interest Rate Derivatives [Abstract]
 
 
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months
$ (0.1)
 
Natural Gas Commodity [Member]
 
 
Gross Notional Amounts of Commodity Options [Abstract]
 
 
Derivative, Nonmonetary Notional amount
18,000 1 2
987,000 1 2
Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
 
 
 
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
$ (361)
$ (437)
$ (514)
After-tax net realized losses on derivative transactions reclassified into earnings
76 
76 
77 
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
$ (285)
$ (361)
$ (437)
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
 
 
 
Derivative instruments designated as fair value hedges
$ 0 
$ 0 
$ 0 
Recognized gains (losses) from fair value hedges or related hedged transactions
0 
0 
0 
Cash Flow Hedges [Member] |
Interest Rate [Member]
 
 
 
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
 
 
 
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net
 
(100,000)
(100,000)
Designated as Hedging Instrument [Member] |
Cash Flow Hedges [Member] |
Interest Rate [Member]
 
 
 
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
 
 
 
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net
(100,000)
 
 
Other Derivative Instruments [Member] |
Natural Gas Commodity [Member]
 
 
 
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
 
 
 
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities
100,000 
(100,000)
(400,000)
Derivative Instruments Gain Loss Reclassified To Regulatory Assets And Liabilities Net
 
$ (700,000)
$ (2,900,000)
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Prepayments and other
$ 6,918 
$ 5,056 
Other current liabilities
19,923 
22,521 
Fair Value Measured on a Recurring Basis |
Other Current Assets [Member] |
Natural Gas Commodity [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
52 1
580 2
Fair Value Measured on a Recurring Basis |
Level 1 |
Other Current Assets [Member] |
Natural Gas Commodity [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
0 
0 
Fair Value Measured on a Recurring Basis |
Level 2 |
Other Current Assets [Member] |
Natural Gas Commodity [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
52 
580 
Fair Value Measured on a Recurring Basis |
Level 3 |
Other Current Assets [Member] |
Natural Gas Commodity [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
0 
0 
Fair Value Measured on a Recurring Basis |
Fair Value Total
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Prepayments and other
6,900 
 
Other current liabilities
 
5,100 
Fair Value Measured on a Recurring Basis |
Fair Value Total |
Other Current Assets [Member] |
Natural Gas Commodity [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
52 
580 
Fair Value Measured on a Recurring Basis |
Netting [Member] |
Other Current Assets [Member] |
Natural Gas Commodity [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 0 3
$ 0 3
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Carrying Amount
 
 
Financial Liabilities, Balance Sheet Groupings [Abstract]
 
 
Long-term debt, including current portion
$ 568,291 
$ 468,597 
Fair Value
 
 
Financial Liabilities, Balance Sheet Groupings [Abstract]
 
 
Long-term debt, including current portion
$ 670,665 
$ 518,269 
Rate Matters (Details) (USD $)
1 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended
May 31, 2014
PSCW Proceeding - Wisconsin Electric Rate Case 2015 [Member]
Public Service Commission of Wisconsin (PSCW)
Dec. 31, 2014
NSP-Wisconsin [Member]
PSCW Proceeding - Wisconsin Electric Rate Case 2015 [Member]
Public Service Commission of Wisconsin (PSCW)
Oct. 31, 2014
NSP-Wisconsin [Member]
MPSC Proceeding - Electric Rate Case 2015, Electric Rates 2016 [Member]
Oct. 31, 2014
NSP-Wisconsin [Member]
MPSC Proceeding - Electric Rate Case 2015, Electric Rates 2015 [Member]
Nov. 30, 2013
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Nov. 30, 2014
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Federal Energy Regulatory Commission (FERC) [Member]
Jun. 30, 2014
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Federal Energy Regulatory Commission (FERC) [Member]
Nov. 30, 2013
Minimum
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Dec. 31, 2014
Minimum
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Nov. 30, 2013
Maximum
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Dec. 31, 2014
Maximum
NSP-Wisconsin [Member]
FERC Proceeding, MISO ROE Complaint [Member]
Feb. 28, 2015
Subsequent Event
FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Public Utilities, Requested Rate Increase (Decrease), Amount
$ 20,600,000 
 
$ 289,000 
$ 900,000 
 
 
 
 
 
 
 
 
Public Utilities, Requested Rate Increase (Decrease), Percentage
3.20% 
 
1.90% 
6.10% 
 
 
 
 
 
 
 
 
Public Utilities, Requested Return on Equity, Percentage
 
 
 
10.30% 
 
 
 
 
 
 
 
 
Public Utilities, Requested Equity Capital Structure, Percentage
 
 
 
52.59% 
 
 
 
 
 
 
 
 
Public Utilities, Requested Rate Base, Amount
 
 
 
35,200,000 
 
 
 
 
 
 
 
 
Public Utilities, Approved Rate Increase (Decrease), Amount
 
14,200,000 
 
 
 
 
 
 
 
 
 
 
Public Utilities, Approved Rate Increase (Decrease), Percentage
 
2.20% 
 
 
 
 
 
 
 
 
 
 
Public Utilities, ROE applicable to transmission formula rates in the MISO region, upper bound, percentage
 
 
 
 
 
 
 
 
 
12.38% 
 
 
Public Utilities, ROE applicable to transmission formula rates in the MISO region, lower bound, percentage
 
 
 
 
 
 
 
9.15% 
 
 
 
 
Public Utilities, maximum equity capital structure percentage allowed per the complaint
 
 
 
 
50.00% 
 
 
 
 
 
 
 
Public Utilities, number of steps required for newly adopted ROE discounted cash flow methodology
 
 
 
 
 
 
2 
 
 
 
 
 
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties
 
 
 
 
 
50 
 
 
 
 
 
50 
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties
 
 
 
 
 
 
 
 
 
 
 
8.67% 
Public Utilities, reduction of transmission revenue, net of expense due to the new ROE methodology
 
 
 
 
 
 
 
 
$ 5,000,000 
 
$ 7,000,000 
 
Commitments and Contingencies, Fuel Contracts (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Fuel Contracts [Abstract]
 
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs (in hundredths)
2.00% 
Coal
 
Fuel Contracts [Abstract]
 
2015
$ 6.6 
2016
0.8 
2017
0.9 
2018
0.8 
2019
0.8 
Thereafter
3.3 
Total
13.2 1
Natural Gas Supply
 
Fuel Contracts [Abstract]
 
2015
12.4 
2016
0.3 
2017
0.2 
2018
0 
2019
0 
Thereafter
0 
Total
12.9 1
Natural Gas Storage and Transportation
 
Fuel Contracts [Abstract]
 
2015
13.2 
2016
13.1 
2017
10.4 
2018
4.7 
2019
3.1 
Thereafter
13.5 
Total
$ 58.0 1
Minimum
 
Unrecorded Unconditional Purchase Obligation [Line Items]
 
Fuel Contract Expiration Date
2015 
Maximum
 
Unrecorded Unconditional Purchase Obligation [Line Items]
 
Fuel Contract Expiration Date
2029 
Commitments and Contingencies, Leases (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Operating Leases [Abstract]
 
 
 
Total expenses under operating lease obligations
$ 1.3 
$ 1.4 
$ 1.1 
Other [Member]
 
 
 
Operating Leases, Future Minimum Payments Due [Abstract]
 
 
 
2015
0.9 
 
 
2016
0.9 
 
 
2017
1.0 
 
 
2018
1.0 
 
 
2019
1.0 
 
 
Thereafter
7.9 
 
 
Total
$ 12.7 
 
 
Commitments and Contingencies, Variable Interest Entities (Details) (Low-Income Housing Limited Partnerships [Member], USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Low-Income Housing Limited Partnerships [Member]
 
 
Amounts Reflected in Consolidated Balance Sheets [Abstract]
 
 
Current assets
$ 246 
$ 223 
Property, plant and equipment, net
2,278 
2,427 
Other noncurrent assets
122 
112 
Total assets
2,646 
2,762 
Current liabilities
1,349 
233 
Mortgages and other long-term debt payable
486 
1,687 
Other noncurrent liabilities
48 
42 
Total liabilities
$ 1,883 
$ 1,962 
Commitments and Contingencies, Joint Operating System (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Counterparty
Joint Operating System [Abstract]
 
Number of companies covered by FERC approved Interchange Agreement
2 
NSP-Minnesota |
Nuclear Insurance
 
Joint Operating System [Abstract]
 
Maximum possible loss contingency
$ 13,600,000,000 
Nuclear insurance coverage secured for the Company's public liability exposure
375,000,000 
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program
13,200,000,000 
Maximum assessments per reactor per accident
127,300,000 
Number of owned and licensed reactors
3 
Maximum funding requirement per reactor for any one year
19,000,000 
Term for maximum installment payment assessment per reactor (in years)
1 year 
Insurance coverage limits for NSP-Minnesota's nuclear plant sites
2,300,000,000 
Number of nuclear plant sites operated by NSP-Minnesota
2 
Maximum assessments for business interruption insurance each calendar year
17,900,000 
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year
$ 43,600,000 
Commitments and Contingencies, Guarantees (Details) (Payment or Performance Guarantee, Customer Loans for Farm Rewiring Program, USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Payment or Performance Guarantee |
Customer Loans for Farm Rewiring Program
 
Guarantee [Abstract]
 
Assets held as collateral
$ 0 
Guarantees issued and outstanding
1.0 1
Current exposure under guarantees
$ 0.2 1
Guarantee Expiration Date (year)
2018 1
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Parties
Site
Dec. 31, 2013
Manufactured Gas Plant (MGP) Site [Abstract]
 
 
Liability for estimated cost of remediating sites, current
$ 29,116,000 
$ 28,785,000 
Ashland MGP Site
 
 
Manufactured Gas Plant (MGP) Site [Abstract]
 
 
Number of properties included in superfund site which NSP-Wisconsin does not own
2 
 
Liability for estimated cost of remediating sites
107,600,000 
104,600,000 
Number of PRPs that have reached a settlement in principle
2 
 
Contributions to site cleanup by PRPs
10,500,000 
 
Number of days the agreement is subject to public comment
30 days 
 
Liability for estimated cost of remediating sites, current
28,900,000 
25,200,000 
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years)
4 years 
 
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years)
6 years 
 
Ashland MGP Site - Phase I Project Area
 
 
Manufactured Gas Plant (MGP) Site [Abstract]
 
 
Liability for estimated cost of remediating sites
54,000,000 
 
Estimated amount spent on Phase I Project Area cleanup
28,000,000 
 
Approved amortization period for recovery of remediation costs in natural gas rates (in years)
10 years 
 
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths)
3.00% 
 
Approved increase (decrease) in amortization expense granted by a regulatory body
1,100,000 
 
Ashland MGP Site - Sediments
 
 
Manufactured Gas Plant (MGP) Site [Abstract]
 
 
Estimated cost of remediating site, low end of range
63,000,000 
 
Estimated cost of remediating site, high end of range
77,000,000 
 
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)
50.00% 
 
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)
30.00% 
 
Other MGP Sites
 
 
Manufactured Gas Plant (MGP) Site [Abstract]
 
 
Liability for estimated cost of remediating sites
$ 200,000 
$ 3,900,000 
Number of identified MGP sites under current investigation and/or remediation
2 
 
Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended
Jun. 30, 2014
Greenhouse Gas New Source Performance Standard for Modified and Reconstructed Power Plants
Apr. 30, 2014
Cross-State Air Pollution Rule
Issue
Apr. 30, 2012
Electric Generating Unit Mercury And Air Toxics Standards Rule
MW
Dec. 31, 2014
National Ambient Air Quality Standards for Ozone
Parts-per-million
Dec. 31, 2014
Capital Commitments
Federal Clean Water Act Section 316(b)
Dec. 31, 2014
Capital Commitments
Industrial Boiler Maximum Achievable Control Technology Rules
Dec. 31, 2014
Minimum
National Ambient Air Quality Standards for Ozone
Parts-per-million
Dec. 31, 2014
Maximum
National Ambient Air Quality Standards for Ozone
Parts-per-million
Environmental Requirements [Abstract]
 
 
 
 
 
 
 
 
Liability for estimated cost to comply with regulation
 
 
 
 
$ 4.0 
$ 21.0 
 
 
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants (in hundredths)
50.00% 
 
 
 
 
 
 
 
Number of issues on which the D.C. Circuit overturned the CSAPR
 
2 
 
 
 
 
 
 
Generating capacity (in MW)
 
 
25 
 
 
 
 
 
Number of years before affected facilities must demonstrate compliance, low end of range
 
 
3 years 
 
 
 
 
 
Number of years before affected facilities must demonstrate compliance, high end of range
 
 
4 years 
 
 
 
 
 
Number of hours the NAAQS for Ozone is based upon (in hours)
 
 
 
8 
 
 
 
 
Current level of air quality concentrations (in parts per million)
 
 
 
0.075 
 
 
 
 
Proposed level of air quality concentrations (in parts per million)
 
 
 
 
 
 
0.065 
0.070 
Lowest proposed level of air quality concentrations that the EPA is taking comment on (in parts per million)
 
 
 
0.060 
 
 
 
 
Commitments and Contingencies, Asset Retirement Obligations (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
$ 2,853 1 2
$ 3,036 
Liabilities recognized
515 
0 
Liabilities settled
0 
0 
Accretion
76 
84 
Cash Flow Revisions
5,646 
(267)
Ending balance
9,090 1 2
2,853 1 2
Electric Plant Steam Production Asbestos
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
2,005 1
1,962 
Liabilities recognized
0 
0 
Liabilities settled
0 
0 
Accretion
44 
43 
Cash Flow Revisions
0 
0 
Ending balance
2,049 1
2,005 1
Electric Plant Steam and Other Production Ash Containment
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
361 1
125 
Liabilities recognized
0 
0 
Liabilities settled
0 
0 
Accretion
13 
12 
Cash Flow Revisions
0 
224 
Ending balance
374 1
361 1
Electric Plant Electric Distribution
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
36 1
13 
Liabilities recognized
0 
0 
Liabilities settled
0 
0 
Accretion
1 
1 
Cash Flow Revisions
0 
22 
Ending balance
37 1
36 1
Electric Plant Other
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
289 1
826 
Liabilities recognized
113 
0 
Liabilities settled
0 
0 
Accretion
10 
20 
Cash Flow Revisions
0 
(557)
Ending balance
412 1
289 1
Natural Gas Plant Gas Distribution
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
75 1
75 
Liabilities recognized
402 
0 
Liabilities settled
0 
0 
Accretion
5 
5 
Cash Flow Revisions
5,645 
(5)
Ending balance
6,127 1
75 1
Common and Other Property Common Miscellaneous
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance
87 1
35 
Liabilities recognized
0 
0 
Liabilities settled
0 
0 
Accretion
3 
3 
Cash Flow Revisions
1 
49 
Ending balance
$ 91 1
$ 87 1
Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) (Plant Removal Costs, USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Plant Removal Costs
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liabilities
$ 123 
$ 116 
Regulatory Assets and Liabilities, Regulatory Assets (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
$ 20,036,000 
$ 14,866,000 
Regulatory Asset, Noncurrent
280,693,000 
233,193,000 
Past expenditures not currently earning a return
12,100,000 
100,000 
Environmental Remediation Costs
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
4,376,000 
4,376,000 
Regulatory Asset, Noncurrent
147,793,000 
117,684,000 
Regulatory asset, remaining amortization period
Various 
 
Pension and Retiree Medical Obligations
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
6,837,000 1
8,202,000 1
Regulatory Asset, Noncurrent
91,601,000 1
85,220,000 1
Regulatory asset, remaining amortization period
Various 
 
Recoverable Deferred Taxes on AFUDC Recorded in Plant
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
0 
0 
Regulatory Asset, Noncurrent
16,711,000 
12,679,000 
Regulatory asset, remaining amortization period
Plant lives 
 
Losses on Reacquired Debt
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
801,000 
801,000 
Regulatory Asset, Noncurrent
4,936,000 
5,737,000 
Regulatory asset, remaining amortization period
Term of related debt 
 
State Commission Adjustments
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
488,000 
410,000 
Regulatory Asset, Noncurrent
11,650,000 
9,355,000 
Regulatory asset, remaining amortization period
Plant lives 
 
Conservation Programs
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
0 
404,000 
Regulatory Asset, Noncurrent
0 
0 
Regulatory asset, remaining amortization period
Less than one year 
 
Deferred Income Tax Adjustment
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
0 
0 
Regulatory Asset, Noncurrent
1,514,000 
1,763,000 
Regulatory asset, remaining amortization period
Typically plant lives 
 
Recoverable Purchased Natural Gas And Electric Energy Costs
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
6,946,000 
673,000 
Regulatory Asset, Noncurrent
0 
0 
Regulatory asset, remaining amortization period
Less than one year 
 
Monticello EPU Cost Deferral
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
0 
0 
Regulatory Asset, Noncurrent
5,237,000 
0 
Regulatory asset, remaining amortization period
Pending rate cases 
 
Other Regulatory Assets
 
 
Regulatory Assets [Line Items]
 
 
Regulatory Asset, Current
588,000 
0 
Regulatory Asset, Noncurrent
$ 1,251,000 
$ 755,000 
Regulatory asset, remaining amortization period
Various 
 
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
$ 16,940 
$ 9,717 
Regulatory Liability, Noncurrent
132,674 
126,424 
Plant Removal Costs
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
0 
0 
Regulatory Liability, Noncurrent
123,105 
116,293 
Regulatory liability, remaining amortization period
Plant lives 
 
DOE Settlement
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
4,931 
6,814 
Regulatory Liability, Noncurrent
0 
0 
Regulatory liability, remaining amortization period
Less than one year 
 
Investment Tax Credit Deferrals
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
0 
0 
Regulatory Liability, Noncurrent
9,397 
9,976 
Regulatory liability, remaining amortization period
Various 
 
Conservation Programs
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
1,010 
1,187 
Regulatory Liability, Noncurrent
0 
0 
Regulatory liability, remaining amortization period
Less than one year 
 
Deferred Electric Production And Natural Gas Costs
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
0 
1,542 
Regulatory Liability, Noncurrent
0 
0 
Regulatory liability, remaining amortization period
Less than one year 
 
Excess depreciation reserve
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
10,999 
0 
Regulatory Liability, Noncurrent
0 
0 
Regulatory liability, remaining amortization period
Various 
 
Other Regulatory Liabilities
 
 
Regulatory Liabilities [Line Items]
 
 
Regulatory Liability, Current
0 
174 
Regulatory Liability, Noncurrent
$ 172 
$ 155 
Regulatory liability, remaining amortization period
Various 
 
Other Comprehensive Income (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
 
 
 
Accumulated other comprehensive income (loss) at beginning of period
$ (361)
 
 
Accumulated other comprehensive income (loss) at end of period
(285)
(361)
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
 
 
 
Total, pre-tax
(113,045)
(95,877)
(79,509)
Income tax expense (benefit)
42,403 
36,409 
29,558 
Gains and Losses on Cash Flow Hedges
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
 
 
 
Accumulated other comprehensive income (loss) at beginning of period
(361)
(437)
 
(Gains) losses reclassified from net accumulated other comprehensive loss
76 
76 
 
Net current period other comprehensive income (loss)
76 
76 
 
Accumulated other comprehensive income (loss) at end of period
(285)
(361)
 
Gains and Losses on Cash Flow Hedges |
Amounts Reclassified from Accumulated Other Comprehensive Loss
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
 
 
 
Total, pre-tax
127 
127 
 
Income tax expense (benefit)
(51)
(51)
 
Total, net of tax
76 
76 
 
Gains and Losses on Cash Flow Hedges |
Interest Rate Derivatives |
Amounts Reclassified from Accumulated Other Comprehensive Loss
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
 
 
 
Interest charges
$ 127 1
$ 127 1
 
Segments and Related Information (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Intercompany revenue
 
 
 
 
 
 
 
 
$ 145,102 
$ 136,917 
$ 125,344 
Operating revenues
256,160 
231,046 
228,114 
285,142 
240,388 
231,060 
210,175 
241,415 
1,000,462 
923,038 
861,842 
Depreciation and amortization
 
 
 
 
 
 
 
 
79,654 
76,897 
69,234 
Total interest charges and financing costs
 
 
 
 
 
 
 
 
25,913 
25,816 
22,937 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
42,403 
36,409 
29,558 
Net income (loss)
14,355 
20,030 
12,022 
24,235 
7,225 
22,013 
10,544 
19,685 
70,642 
59,468 
49,951 
Regulated Electric
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
830,245 
789,518 
757,920 
Depreciation and amortization
 
 
 
 
 
 
 
 
65,978 
64,237 
59,768 
Total interest charges and financing costs
 
 
 
 
 
 
 
 
23,448 
22,966 
20,303 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
39,621 
33,691 
27,164 
Net income (loss)
 
 
 
 
 
 
 
 
59,060 
51,334 
45,377 
Regulated Natural Gas
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
174,514 
134,834 
103,827 
Depreciation and amortization
 
 
 
 
 
 
 
 
13,501 
12,485 
9,251 
Total interest charges and financing costs
 
 
 
 
 
 
 
 
2,358 
2,749 
2,554 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
5,993 
4,623 
2,113 
Net income (loss)
 
 
 
 
 
 
 
 
8,714 
6,501 
3,094 
All Other
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
1,085 
1,003 
1,177 
Depreciation and amortization
 
 
 
 
 
 
 
 
175 
175 
215 
Total interest charges and financing costs
 
 
 
 
 
 
 
 
107 
101 
80 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
(3,211)
(1,905)
281 
Net income (loss)
 
 
 
 
 
 
 
 
2,868 
1,633 
1,480 
Operating Segments
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
1,000,462 1
923,038 1
861,842 1
Operating Segments |
Regulated Electric
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
829,748 1
789,168 1
757,565 1
Operating Segments |
Regulated Natural Gas
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
169,629 1
132,867 1
103,100 1
Operating Segments |
All Other
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
1,085 1
1,003 1
1,177 1
Intersegment Eliminations
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
(5,382)
(2,317)
(1,082)
Depreciation and amortization
 
 
 
 
 
 
 
 
0 
0 
0 
Total interest charges and financing costs
 
 
 
 
 
 
 
 
0 
0 
0 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
0 
0 
0 
Net income (loss)
 
 
 
 
 
 
 
 
0 
0 
0 
Intersegment Eliminations |
Regulated Electric
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
497 
350 
355 
Intersegment Eliminations |
Regulated Natural Gas
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
4,885 
1,967 
727 
Intersegment Eliminations |
All Other
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
$ 0 
$ 0 
$ 0 
Schedule II, Valuation and Qualifying Accounts (Details) (Allowance for Bad Debts, USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Allowance for Bad Debts
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Jan. 1
$ 4,911 
$ 4,333 
$ 4,766 
Charged to costs and expenses
4,431 
3,988 
3,329 
Charged to other accounts
1,269 1
1,199 1
1,310 1
Deductions from reserves
4,790 2
4,609 2
5,072 2
Balance at Dec. 31
$ 5,821 
$ 4,911 
$ 4,333 
Related Party Transactions (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Related Party Transaction [Line Items]
 
 
 
Deferred Purchased Power Costs
$ 5,200,000 
 
 
Transmission costs deferred as regulatory liability
11,000,000 
 
 
Operating revenues
 
 
 
Electric
145,102,000 
136,917,000 
125,344,000 
Related Party Transaction, Utilities Operating Expense, Purchased Power net of deferred costs
430,666,000 1
 
 
Operating expenses
 
 
 
Purchased power
425,471,000 
416,173,000 
405,016,000 
Transmission expense
43,876,000 
42,460,000 
44,942,000 
Natural gas purchased for resale
90,000 
97,000 
116,000 
Other operating expenses - paid to Xcel Energy Services Inc.
84,224,000 
61,531,000 
54,137,000 
Interest expense
30,000 
22,000 
22,000 
Accounts Receivable and Payable with Affiliates [Abstract]
 
 
 
Accounts receivable
31,000 
1,595,000 
 
Accounts payable
26,524,000 
24,986,000 
 
NSP-Minnesota
 
 
 
Accounts Receivable and Payable with Affiliates [Abstract]
 
 
 
Accounts receivable
0 
0 
 
Accounts payable
17,333,000 
18,584,000 
 
PSCo
 
 
 
Accounts Receivable and Payable with Affiliates [Abstract]
 
 
 
Accounts receivable
0 
0 
 
Accounts payable
22,000 
8,000 
 
SPS
 
 
 
Accounts Receivable and Payable with Affiliates [Abstract]
 
 
 
Accounts receivable
31,000 
26,000 
 
Accounts payable
0 
0 
 
Other subsidiaries of Xcel Energy Inc.
 
 
 
Accounts Receivable and Payable with Affiliates [Abstract]
 
 
 
Accounts receivable
0 
1,569,000 
 
Accounts payable
$ 9,169,000 
$ 6,394,000 
 
Summarized Quarterly Financial Data (Unaudited) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 256,160 
$ 231,046 
$ 228,114 
$ 285,142 
$ 240,388 
$ 231,060 
$ 210,175 
$ 241,415 
$ 1,000,462 
$ 923,038 
$ 861,842 
Operating income
27,787 
37,540 
23,730 
42,571 
16,545 
40,769 
22,466 
37,401 
131,628 
117,181 
99,866 
Net income
$ 14,355 
$ 20,030 
$ 12,022 
$ 24,235 
$ 7,225 
$ 22,013 
$ 10,544 
$ 19,685 
$ 70,642 
$ 59,468 
$ 49,951