Edgar Filing: XCEL ENERGY INC

(Amounts in Thousands) ^(a)(b)

March 31, 2015

Dec. 31, 2014

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel

XCEL 3.31.15 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2015



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)



Minnesota		41-0448030
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

414 Nicollet Mall
Minneapolis, Minnesota		55401
(Address of principal executive offices)		(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company ¨
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Outstanding at April 27, 2015
Common Stock, $2.50 par value		506,914,489 shares

TABLE OF CONTENTS



PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	3
	CONSOLIDATED STATEMENTS OF INCOME	3
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	4
	CONSOLIDATED STATEMENTS OF CASH FLOWS	5
	CONSOLIDATED BALANCE SHEETS	6
	CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY	7
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	8
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4 —	Controls and Procedures	53

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	53
Item 1A —	Risk Factors	53
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 4 —	Mine Safety Disclosures	53
Item 5 —	Other Information	53
Item 6 —	Exhibits	54

SIGNATURES		55

	Certifications Pursuant to Section 302	1
	Certifications Pursuant to Section 906	1
	Statement Pursuant to Private Litigation	1

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

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in thousands, except per share data)

	Three Months Ended March 31
	2015			2014
Operating revenues
Electric	$	2,224,863		$	2,301,710
Natural gas	715,996			879,688
Other	21,360			21,206
Total operating revenues	2,962,219			3,202,604

Operating expenses
Electric fuel and purchased power	950,132			1,067,321
Cost of natural gas sold and transported	472,371			623,828
Cost of sales — other	10,049			9,129
Operating and maintenance expenses	585,830			560,143
Conservation and demand side management program expenses	53,805			77,546
Depreciation and amortization	273,098			245,943
Taxes (other than income taxes)	136,626			124,702
Loss on Monticello life cycle management/extended power uprate project	129,463			—
Total operating expenses	2,611,374			2,708,612

Operating income	350,845			493,992

Other income, net	3,161			3,201
Equity earnings of unconsolidated subsidiaries	7,776			7,438
Allowance for funds used during construction — equity	12,660			21,907

Interest charges and financing costs
Interest charges — includes other financing costs of $5,698 and $5,792, respectively	144,940			139,094
Allowance for funds used during construction — debt	(6,144		)	(9,548		)
Total interest charges and financing costs	138,796			129,546

Income before income taxes	235,646			396,992
Income taxes	83,580			135,771
Net income	$	152,066		$	261,221

Weighted average common shares outstanding:
Basic	506,983			499,523
Diluted	507,393			499,746

Earnings per average common share:
Basic	$	0.30		$	0.52
Diluted	0.30			0.52

Cash dividends declared per common share	$	0.32		$	0.30

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in thousands)

	Three Months Ended March 31
	2015			2014
Net income	$	152,066		$	261,221

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $569 and $550, respectively	876			864

Derivative instruments:
Net fair value decrease, net of tax of $(7) and $(5), respectively	(11		)	(7		)
Reclassification of losses to net income, net of tax of $382 and $358, respectively	585			560
	574			553
Marketable securities:
Net fair value increase, net of tax of $0 and $24, respectively	1			38

Other comprehensive income	1,451			1,455
Comprehensive income	$	153,517		$	262,676

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in thousands)

	Three Months Ended March 31
	2015			2014
Operating activities
Net income	$	152,066		$	261,221
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	277,388			250,343
Conservation and demand side management program amortization	1,451			1,555
Nuclear fuel amortization	28,465			28,862
Deferred income taxes	82,773			150,464
Amortization of investment tax credits	(1,384		)	(1,443		)
Allowance for equity funds used during construction	(12,660		)	(21,907		)
Equity earnings of unconsolidated subsidiaries	(7,776		)	(7,438		)
Dividends from unconsolidated subsidiaries	9,876			8,850
Share-based compensation expense	10,225			5,370
Loss on Monticello life cycle management/extended power uprate project	129,463			—
Net realized and unrealized hedging and derivative transactions	12,778			7,384
Changes in operating assets and liabilities:
Accounts receivable	(291		)	(140,962		)
Accrued unbilled revenues	183,974			111,417
Inventories	92,010			140,301
Other current assets	56,685			(66,320		)
Accounts payable	(99,029		)	(37,730		)
Net regulatory assets and liabilities	146,097			(253		)
Other current liabilities	34,642			1,008
Pension and other employee benefit obligations	(85,469		)	(125,780		)
Change in other noncurrent assets	(5		)	48,054
Change in other noncurrent liabilities	(25,885		)	(20,347		)
Net cash provided by operating activities	985,394			592,649

Investing activities
Utility capital/construction expenditures	(770,609		)	(822,628		)
Proceeds from insurance recoveries	24,241			4,260
Allowance for equity funds used during construction	12,660			21,907
Purchases of investments in external decommissioning fund	(387,826		)	(229,548		)
Proceeds from the sale of investments in external decommissioning fund	386,111			227,901
Investment in WYCO Development LLC	(321		)	(1,161		)
Other, net	(2,645		)	(1,501		)
Net cash used in investing activities	(738,389		)	(800,770		)

Financing activities
(Repayments of) proceeds from short-term borrowings, net	(50,500		)	6,000
Proceeds from issuance of long-term debt	—			295,999
Repayments of long-term debt	(455		)	(224		)
Proceeds from issuance of common stock	1,411			63,548
Dividends paid	(144,025		)	(132,033		)
Net cash (used in) provided by financing activities	(193,569		)	233,290

Net change in cash and cash equivalents	53,436			25,169
Cash and cash equivalents at beginning of period	79,608			107,144
Cash and cash equivalents at end of period	$	133,044		$	132,313

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(161,717	)	$	(152,522	)
Cash received (paid) for income taxes, net	62,697			(164		)

Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	239,905		$	290,058
Issuance of common stock for reinvested dividends and 401(k) plans	14,433			14,525

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in thousands, except share and per share data)

	March 31, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	133,044		$	79,608
Accounts receivable, net	826,797			826,506
Accrued unbilled revenues	544,518			728,492
Inventories	505,213			597,183
Regulatory assets	351,780			444,058
Derivative instruments	38,905			85,723
Deferred income taxes	383,463			246,210
Prepaid taxes	118,291			185,488
Prepayments and other	155,435			171,112
Total current assets	3,057,446			3,364,380

Property, plant and equipment, net	28,966,911			28,756,916

Other assets
Nuclear decommissioning fund and other investments	1,867,425			1,832,640
Regulatory assets	2,760,522			2,774,216
Derivative instruments	51,739			53,775
Other	174,608			175,957
Total other assets	4,854,294			4,836,588
Total assets	$	36,878,651		$	36,957,884

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	257,399		$	257,726
Short-term debt	969,000			1,019,500
Accounts payable	898,003			1,173,006
Regulatory liabilities	393,054			410,729
Taxes accrued	480,311			396,615
Accrued interest	131,579			158,536
Dividends payable	162,130			151,720
Derivative instruments	19,615			21,632
Other	463,437			475,119
Total current liabilities	3,774,528			4,064,583

Deferred credits and other liabilities
Deferred income taxes	6,085,780			5,852,988
Deferred investment tax credits	72,312			73,696
Regulatory liabilities	1,185,477			1,163,429
Asset retirement obligations	2,476,049			2,446,631
Derivative instruments	178,957			183,936
Customer advances	253,895			256,945
Pension and employee benefit obligations	850,826			936,907
Other	286,487			264,653
Total deferred credits and other liabilities	11,389,783			11,179,185

Commitments and contingencies
Capitalization
Long-term debt	11,499,470			11,499,634
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 506,663,770 and 505,733,267 shares outstanding at March 31, 2015 and Dec. 31, 2014, respectively	1,266,659			1,264,333
Additional paid in capital	5,844,995			5,837,330
Retained earnings	3,209,904			3,220,958
Accumulated other comprehensive loss	(106,688		)	(108,139		)
Total common stockholders’ equity	10,214,870			10,214,482
Total liabilities and equity	$	36,878,651		$	36,957,884

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in thousands)

	Common Stock Issued					Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
Three Months Ended March 31, 2015 and 2014
Balance at Dec. 31, 2013	497,972	$	1,244,929	$	5,619,313	$	2,807,983		$	(106,275	)	$	9,565,950
Net income						261,221						261,221
Other comprehensive income									1,455			1,455
Dividends declared on common stock						(150,989		)				(150,989		)
Issuances of common stock	3,180	7,950		55,772								63,722
Share-based compensation				6,065								6,065
Balance at March 31, 2014	501,152	$	1,252,879	$	5,681,150	$	2,918,215		$	(104,820	)	$	9,747,424

Balance at Dec. 31, 2014	505,733	$	1,264,333	$	5,837,330	$	3,220,958		$	(108,139	)	$	10,214,482
Net income						152,066						152,066
Other comprehensive income									1,451			1,451
Dividends declared on common stock						(163,120		)				(163,120		)
Issuances of common stock	931	2,326		893								3,219
Share-based compensation				6,772								6,772
Balance at March 31, 2015	506,664	$	1,266,659	$	5,844,995	$	3,209,904		$	(106,688	)	$	10,214,870

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of March 31, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2015 and 2014; and its cash flows for the three months ended March 31, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2015 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014, filed with the SEC on Feb. 20, 2015. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, is effective for interim and annual reporting periods beginning after Dec. 15, 2016. In April 2015, the FASB tentatively decided to defer the effective date by one year, making the guidance effective for interim and annual reporting periods beginning after Dec. 15, 2017. This tentative decision will be exposed for public input in an upcoming proposed ASU with a 30-day comment period. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU 2015-02 on its consolidated financial statements.

Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, Xcel Energy does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	882,625		$	884,225
Less allowance for bad debts	(55,828		)	(57,719		)
	$	826,797		$	826,506

Table of Contents



(Thousands of Dollars)	March 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	254,385	$	244,099
Fuel	174,149		183,249
Natural gas	76,679		169,835
	$	505,213	$	597,183



(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	33,541,957		$	33,203,139
Natural gas plant	4,692,601			4,643,452
Common and other property	1,619,160			1,611,486
Plant to be retired ^(a)	64,130			71,534
Construction work in progress	2,010,792			2,005,531
Total property, plant and equipment	41,928,640			41,535,142
Less accumulated depreciation	(13,373,008		)	(13,168,418		)
Nuclear fuel	2,396,974			2,347,422
Less accumulated amortization	(1,985,695		)	(1,957,230		)
	$	28,966,911		$	28,756,916


^(a)	PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.


4.	Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — Xcel Energy files a consolidated federal income tax return. 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 Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 2015, 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. As of March 31, 2015, the IRS has begun the Appeals process; however, the outcome and timing of a resolution is uncertain.

State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of March 31, 2015, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:



State		Year
Colorado		2009
Minnesota		2009
Texas		2009
Wisconsin		2010

As of March 31, 2015, there were no state income tax audits in progress.

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

Table of Contents

A reconciliation of the amount of unrecognized tax benefit is as follows:



(Millions of Dollars)	March 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	16.3	$	16.2
Unrecognized tax benefit — Temporary tax positions	53.7		50.3
Total unrecognized tax benefit	$	70.0	$	66.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:



(Millions of Dollars)	March 31, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(31.9	)	$	(28.5	)

It is reasonably possible that Xcel Energy’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 appeals process moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $10 million.

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 March 31, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2015 or Dec. 31, 2014.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

NSP-Minnesota – Minnesota 2014 Multi-Year Electric Rate Case — In November 2013, NSP-Minnesota filed a two-year electric rate case with the MPUC. The rate case was based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015. The NSP-Minnesota electric rate case initially reflected a requested increase in revenues of approximately $193 million, or 6.9 percent, in 2014 and an additional $98 million, or 3.5 percent, in 2015. The request included a proposed rate moderation plan for 2014 and 2015. In December 2013, the MPUC approved interim rates of $127 million, effective Jan. 3, 2014, subject to refund.

In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million.

In December 2014, the administrative law judge (ALJ) issued her recommendations in the NSP-Minnesota electric rate case. NSP-Minnesota estimated that her recommendations would have resulted in a rate increase of $69.1 million in 2014 and an incremental rate increase of $122.4 million in 2015. In addition, she recommended an ROE of 9.77 percent and an equity ratio of 52.5 percent.

On March 26, 2015, the MPUC voted to approve a 2014 rate increase and a 2015 step increase. NSP-Minnesota estimates the total rate increase to be approximately $168 million, or 6.1 percent, based on a 9.72 percent ROE and 52.50 percent equity ratio. The MPUC largely approved the ALJ’s recommendations and the excess depreciation reserve utilization of 50 percent, 30 percent and 20 percent in 2014, 2015, and 2016, respectively. The MPUC did not adopt NSP-Minnesota’s 2016 rate case avoidance proposal. NSP-Minnesota is initiating the preparation of its 2016 rate case. NSP-Minnesota will evaluate how best to proceed including whether proposed legislation could provide alternative approaches, whether rate moderation is available and whether to propose a single or multi-year request.

Table of Contents

The following table reconciles NSP-Minnesota’s original request to the MPUC's March 26, 2015 verbal decision, including the estimated ongoing impact of their March 6, 2015 verbal decision in the Monticello Prudence Review on the Minnesota retail electric jurisdiction:



2014 Rate Request (Millions of Dollars)	NSP-Minnesota			ALJ			MPUC Decision
NSP-Minnesota’s filed rate request	$	192.7		$	192.7		$	192.7
Sales forecast (with true-up to 12 months of actual weather-normalized sales)	(38.5		)	(38.5		)	(38.5		)
ROE	—			(28.4		)	(31.9		)
Monticello extended power uprate (EPU) cost recovery	(12.2		)	(31.3		)	(37.6		)
Property taxes (with true-up to actual 2014 accruals)	(13.2		)	(13.2		)	(13.2		)
Prairie Island EPU cost recovery	(5.1		)	(5.1		)	(5.1		)
Health care, pension and other benefits	(1.9		)	(1.9		)	(3.0		)
Other, net	(6.5		)	(5.2		)	(5.3		)
Total 2014	$	115.3		$	69.1		$	58.1



2015 Rate Request (Millions of Dollars)	NSP-Minnesota			ALJ			MPUC Decision
NSP-Minnesota’s filed rate request	$	98.5		$	98.5		$	98.5
Monticello EPU cost recovery	11.7			29.1			35.4
Depreciation / Retirements	—			—			(0.5		)
Property taxes	(3.3		)	(3.3		)	(3.3		)
Production tax credits to be included in base rates	(11.1		)	(11.1		)	(11.1		)
U.S. Department of Energy (DOE) settlement proceeds	10.1			10.1			10.1
Emission chemicals	(1.6		)	(1.6		)	(1.6		)
Other, net	1.7			0.7			0.2
Total 2015 step increase - prior to Monticello EPU cost disallowance	$	106.0		$	122.4		$	127.7

Total for 2014 and 2015 step increase - prior to Monticello EPU cost disallowance	$	221.3		$	191.5		$	185.8
Monticello EPU cost disallowance - ongoing impact	—			—			(18.2		)
Total for 2014 and 2015 step increase - including Monticello EPU cost disallowance	$	221.3		$	191.5		$	167.6

The MPUC also approved a full revenue decoupling three-year pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of weather variability on electric sales for these classes. NSP-Minnesota can seek to recover amounts over the cap provided it can show that its demand-side management and/or other initiatives were a substantial contributing factor to the declining energy consumption and that other non-conservation factors were not the primary factors for the under-recovery.

The MPUC made no determination on NSP-Minnesota's interim rate refund proposal. There are currently two proposals in the case regarding the potential refund for interim rates for 2014 and 2015. NSP-Minnesota has requested that the MPUC treat the multi-year case as a single period and net the two-year period for any potential refund/surcharge that could occur when final rates are established. The Minnesota Department of Commerce identified an alternative option that views each year of the multi-year case separately, which would result in lower 2015 revenues by approximately $3.5 million per month between Jan. 1, 2015 and the date that final rates are determined. The final order is expected to be issued May 8, 2015. NSP-Minnesota filed the initial parts of a compliance filing calculating the final authorized rates in April 2015 and plans to file the remaining portions during May 2015. The MPUC is expected to rule on interim rates after the comment period for the compliance filing.

NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

Table of Contents

On March 6, 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used and useful for 2014. As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC.

In addition, the decision would reduce the 2015 revenue requirement and pre-tax income for Xcel Energy (assuming other state commissions adopt the MPUC decision) and the Minnesota retail electric jurisdiction as follows:



(Millions of Dollars)	Revenue		Pre-tax Income (a)
Xcel Energy	$	25	$	16
Minnesota retail electric jurisdiction	18		12


^(a)	Pre-tax income reflects the net impact of the reductions in revenue and depreciation expense.

Review of the final written order, which is anticipated in the second quarter of 2015, could impact NSP-Minnesota’s calculations. NSP-Minnesota will have the ability to file for reconsideration.

NSP-Minnesota – 2015 Transmission Cost Recovery (TCR) Rate Filing — In October 2014, the 2015 NSP-Minnesota TCR filing was filed with the MPUC, requesting recovery of $65.8 million of 2015 transmission investment costs not previously included in electric base rates. An MPUC decision is anticipated in the second quarter of 2015, with implementation of new rates soon after approval.

Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

NSP-Minnesota – South Dakota 2015 Electric Rate Case — In June 2014, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. The request is based on a 2013 historic test year (HTY) adjusted for certain known and measurable changes for 2014 and 2015, a requested ROE of 10.25 percent, an average rate base of $433.2 million and an equity ratio of 53.86 percent. This request reflects NSP-Minnesota’s proposal to move recovery of approximately $9.0 million for certain TCR rider and Infrastructure rider projects to base rates.

Interim rates of $15.6 million, subject to refund, went into effect in January 2015. At this time, the parties are in settlement discussion and further procedure scheduling may be established, as necessary. Final rates are anticipated to be effective mid-2015.

PSCo

Pending and Recently Concluded Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

PSCo – Colorado 2014 Electric Rate Case — In 2014, PSCo filed an electric rate case with the CPUC requesting an increase in annual revenue of approximately $136.0 million, or 4.83 percent. The requested 2015 rate increase reflected approximately $100.9 million (subsequently updated to $98.7 million) for recovery of costs associated with the Clean Air Clean Jobs Act (CACJA) project. The case also requested the initiation of a CACJA rider for 2016 and 2017, which was anticipated to increase revenue recovery by approximately $34.2 million in 2016 and then decline to approximately $29.9 million in 2017.

In December 2014, PSCo filed rebuttal testimony, revising its requested rate increase to $107.2 million, or 3.79 percent, reflecting an ROE of 10.25 percent and updated information for both the sales and property tax forecasts. PSCo also proposed to recover all costs associated with the CACJA project through the rider beginning in 2015.

Table of Contents

In February 2015, the CPUC approved a settlement agreement with rates effective on Feb. 13, 2015. This agreement results in an overall 2015 revenue increase of approximately $53.3 million, or 1.87 percent. Key terms of the agreement include the following:


•	The settlement is based on a 2013 HTY, an ROE of 9.83 percent and an equity ratio of 56 percent;


•	The implementation of a forward-looking CACJA rider of approximately $97.0 million for 2015 with step increases of $17.7 million and $14.5 million for 2016 and 2017, respectively, effective Jan. 1, 2015;


•	A forward-looking transmission cost adjustment (TCA) rider of approximately $15.6 million, effective Feb. 13, 2015;


•	Establishment of tracking mechanisms for pension expense and property taxes; and


•	An earnings test for 2015 through 2017, under which PSCo and customers would share in any earnings on a 50/50 basis if the ROE recognized falls between 9.84 percent and 10.48 percent.

The components of the overall 2015 revenue increase are as follows:



(Millions of Dollars)	Approved Settlement
Total base rate decrease	$	(39.4	)
CACJA rider mechanism	97.0
TCA rider mechanism	15.6
Transfer from TCA rider to base rates	(19.9		)
Total revenue increase	$	53.3

In addition to the revenue increase of $53.3 million, including the impact of the riders, PSCo estimates that it will defer approximately $3.1 million of additional expenses in 2015 as a result of the settlement.

PSCo – Colorado 2015 Multi-Year Gas Rate Case — On March 3, 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests a ROE of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

PSCo is also proposing a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and to implement an earnings test for 2016 through 2017. Under the earnings test, PSCo and customers would share in any earnings on a 50/50 basis if the ROE recognized falls between 10.2 percent and 10.6 percent in 2016, and between 10.4 percent and 10.8 percent in 2017.

In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts, including accelerated system renewal projects. If the PSIA rider is not extended by Dec. 31, 2015, such costs would be included in base rates. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. If PSCo's proposal is accepted, PSIA revenue is projected to be $67.0 million in 2015, $88.7 million in 2016, and $109.9 million in 2017.

Table of Contents

The following table summarizes the request:



(Millions of Dollars)	2015			2016 Step			2017 Step
Net plant and plant related expenses	$	24.4		$	12.4		$	12.0
Operating and maintenance expenses	23.9			(5.2		)	0.6
Property and payroll taxes	4.7			2.6			4.0
ROE	4.5			—			2.4
Capital structure	(1.0		)	—			0.1
Sales forecast	(17.1		)	(2.2		)	(1.0		)
Other, net	1.1			—			—
Total base rate increase	40.5			7.6			18.1
Incremental PSIA rider revenues	(0.1		)	21.7			21.2
Total revenue impact	$	40.4		$	29.3		$	39.3

In March 2015, the CPUC referred the proceeding to an ALJ. A CPUC decision, as well as implementation of final rates, are anticipated in the fourth quarter of 2015.

PSCo – Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012 through 2014. On April 30, 2015, PSCo filed a tariff for the 2014 earnings test with the CPUC proposing a refund obligation of $66.5 million to electric customers.

In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. The current estimate of the 2015 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of March 31, 2015.

Electric, Purchased Gas and Resource Adjustment Clauses

Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million.

In October 2014, PSCo filed its 2015-2016 DSM plan, which proposes a 2015 DSM electric budget of $81.6 million and a gas budget of $13.1 million and a 2016 DSM electric budget of $78.7 million and gas budget of $13.6 million. PSCo has reached an agreement with all parties resolving most of the contested issues in the proceeding. The remaining issues to be litigated primarily concern the avoided costs attributable to DSM measures. A decision by the ALJ is expected in the second quarter of 2015.

SPS

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

SPS – Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric, non-fuel rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on an HTY ended June 2014, adjusted for known and measurable changes, an ROE of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent. In March 2015, SPS revised its requested increase to $58.9 million based on updated information.

As part of its request, SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

Table of Contents

The following table summarizes the net request:



(Millions of Dollars)	Request
Investment for capital expenditures — post-test year adjustments	$	23.7
Depreciation expense	13.9
Wholesale load reductions	12.0
Purchased power capacity costs	3.2
Other, net	6.1
Total	$	58.9

In April 2015, a revised procedural schedule was established. The next steps are expected to be as follows:


•	Intervenor Direct Testimony — May 15, 2015;


•	Staff Direct Testimony — May 22, 2015;


•	Staff and Intervenor Cross-Rebuttal Testimony — June 8, 2015;


•	Rebuttal Testimony — June 10, 2015; and


•	Evidentiary Hearing — June 24, 2015.

The parties have agreed the rates will be effective June 11, 2015. A PUCT decision is anticipated in the second half of 2015.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

SPS – Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

The FERC established effective dates for the refunds as April 20, 2012 (first refund period) and July 19, 2013 (second refund period). Settlement judge procedures were unsuccessful and the complaints were set for hearings. In the first quarter of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:



	Refund Period	Production ROE		Transmission ROE ^(a)
Golden Spread	1	8.78	%	9.28	%
	2	8.51		9.01
SPS	1	10.25		10.39
	2	10.25		11.20
FERC Staff	1	8.97		9.47
	2	8.64		9.14


^(a)	Includes a Southwest Power Pool, Inc. (SPP) RTO membership adder up to 50 basis points.

Hearings are scheduled for July 2015. An initial ALJ decision is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016.

A third rate complaint was filed in October 2014 by Golden Spread, along with certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico cooperatives and SPS transmission formula rate, which includes an SPP RTO membership adder up to 50 basis points, be reduced to 8.61 percent and 9.11 percent, respectively. The complainants requested a refund effective date of Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. A hearing is scheduled for October 2015, with an ALJ initial decision expected in January 2016, and a final FERC order following later in 2016.

Table of Contents

SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of March 31, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.

SPS – 2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12CP system.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.8 million of principal and interest was accrued during 2015.

SPS – 2015 Formula Rate Change Filing — In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties are engaged in settlement judge procedures.

Pending Regulatory Proceedings — FERC

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

In 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 TOs for settlement 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 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 TOs 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. The FERC has to date taken no action on the second complaint.

Table of Contents

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of March 31, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5, Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity.

The Xcel Energy utility subsidiaries had approximately 3,698 MW of capacity under long-term PPAs as of March 31, 2015 and Dec. 31, 2014, with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033.

Guarantees and Bond Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of March 31, 2015 and Dec. 31, 2014, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy Inc.:



(Millions of Dollars)	March 31, 2015		Dec. 31, 2014
Guarantees issued and outstanding	$	13.9	$	13.9
Current exposure under these guarantees	0.1		0.2
Bonds with indemnity protection	31.9		31.4

Other Indemnification Agreements

Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.

Environmental Contingencies

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

Table of Contents

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

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 Wisconsin Department of Natural Resources, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including excavation and treatment, as well as containment wall remedies were completed in early 2015. 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. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million, of which approximately $33 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.

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 early 2015, the EPA granted an extension of time to perform the pilot in 2016 so that NSP-Wisconsin can first construct a breakwater at the site to serve as a wave attenuator.

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 commenced on April 27, 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 final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also has entered a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs will contribute $10.5 million and LE Myers Co. will contribute $5.4 million to the costs of the cleanup at the Ashland site. The agreement for the Railroad PRPs along with LE Myers Co. was approved by the U.S. District Court for the Western District of Wisconsin in 2015. As discussed below, existing Public Service Commission of Wisconsin (PSCW) policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers.

At March 31, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $112.4 million and $107.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $26.0 million and $28.9 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.

Table of Contents

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 NSP-Wisconsin rate recovery for 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.

The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin's 2013 general rate case. In their final decision, dated Dec. 27, 2012, 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 a 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 and 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. Cost recovery will continue at the level set in the 2014 rate case though 2015, but will be re-assessed in NSP-Wisconsin’s next natural gas rate case.

Environmental Requirements

Water and Waste

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment, and disposal of solid waste. On April 17, 2015, the EPA published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste. Xcel Energy’s costs to manage and dispose of coal ash will not significantly increase under the new rule.

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrous oxide (NOx) from utilities in the eastern half of the United States using an emissions trading program. For Xcel Energy, the rule applies in Minnesota, Wisconsin and Texas.

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the CAIR pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (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. An opinion is expected late summer 2015. 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. While the litigation continues, the EPA will administer the CSAPR in 2015.

Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million.

NSP-Minnesota can operate within its CSAPR emission allowance allocations. NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO₂. 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.

Table of Contents

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Colorado, Minnesota and Texas identified the Xcel Energy facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

PSCo

In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable in rates.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the Colorado SIP. WildEarth Guardians has challenged the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction (SCR) be added to the units. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In its February 2015 status report to the Court the EPA estimated that it would submit a final rule for publication which is expected in 2015.

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

NSP-Minnesota

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO₂. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota anticipates these costs will be fully recoverable in rates.

After the CSAPR was adopted in 2011, the MPCA supplemented its Minnesota SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, the EPA approved the Minnesota SIP for electric generating units (EGUs) and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. In October 2014, the Eighth Circuit set a briefing schedule that was completed in February 2015. An argument date has not been set. If this litigation ultimately results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

SPS

Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP (the Texas SIP) that finds the Clean Air Interstate Rule (CAIR) equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the Texas SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in August 2015.

Table of Contents

In May 2014, the EPA issued a request for information under the CAA related to SO₂ control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the Texas SIP and instead adopt a Federal Implementation Plan. For SPS, the EPA proposed to require dry scrubbers on both Tolk units to reduce SO₂ emissions to help achieve reasonable progress goals the EPA would establish for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in August 2015. SPS filed comments in April 2015, opposing the proposal. Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million, with an annual operating cost of approximately $10.4 million.

Reasonably Attributable Visibility Impairment (RAVI) — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination whether there is RAVI-type impairment in these parks and examine which sources may cause or contribute to any RAVI impact that is identified. After studying the national parks and evaluating multiple sources, if the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.

In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene.

In June 2014, the EPA and the plaintiffs lodged a consent decree with the District Court. The public comment period on the draft consent decree has been completed. The EPA has not filed a motion to enter the consent decree with the District Court.

Legal Contingencies

Xcel Energy 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 Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Table of Contents

Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint — Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved Qualifying Facilities (QF) Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. On Jan.16, 2015, Exelon Wind filed motions to dismiss or notices of non-suits for its state and federal lawsuits regarding the QF tariff, and for its state and federal lawsuits and regulatory proceedings regarding the LEOs. Later in January, the PUCT and state and federal courts issued orders dismissing the cases. On April 28, 2015, Exelon Wind filed a notice of withdrawal of its complaint regarding the LEOs, which will become effective on May 13, 2015. The only remaining proceeding is pending before the FERC, and involves the QF Tariff.

SPS believes the likelihood of loss in these proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. The City of Seattle filed a petition for review with the Court of Appeals for the Ninth Circuit seeking review of FERC’s order on remand.

Notwithstanding its petition for review, in September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

Table of Contents

A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle contested the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. This matter is now pending a decision by the FERC.

In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, such as PSCo, are required to submit briefs on or before May 8, 2015. Oral argument is scheduled to commence in June 2015.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

Biomass Fuel Handling Reimbursement — NSP-Minnesota has a PPA through which it procures energy from Fibrominn, LLC (Fibrominn). Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Fibrominn’s generation facility. Fibrominn has demanded additional cost reimbursement for certain transportation costs incurred since 2007, as well as reimbursement for similar costs in future periods. Fibrominn claims that it is entitled to reimbursement from NSP-Minnesota for past transportation costs of approximately $20 million. NSP-Minnesota has evaluated Fibrominn’s claim and based on the terms of the PPA with Fibrominn and its current understanding of the facts, NSP-Minnesota disputes the validity of Fibrominn’s claim, on the ground that, among other things, it seeks to impose contractual obligations on NSP-Minnesota that are neither supported by the terms nor the intent of the PPA. NSP-Minnesota has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, NSP-Minnesota is currently unable to determine the amount of reasonably possible loss. If a loss were sustained, NSP-Minnesota would attempt to recover these fuel-related costs in rates. No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the DOE’s failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the Court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. In January 2014, the United States proposed, and NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs for used fuel storage after 2016; such costs could be the subject of future litigation. In December 2014, NSP-Minnesota received a settlement payment of $32.8 million. NSP-Minnesota has received a total of $214.7 million of settlement proceeds as of March 31, 2015. Amounts received from the installments, except for approved reductions such as legal costs, will be subsequently returned to customers through a reduction of future rate increases or credited through another regulatory mechanism.

Table of Contents


7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.

Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:



(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	2,750		$	2,750
Amount outstanding at period end	969			1,020
Average amount outstanding	1,076			841
Maximum amount outstanding	1,360			1,200
Weighted average interest rate, computed on a daily basis	0.46		%	0.33		%
Weighted average interest rate at period end	0.55			0.56

Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2015 and Dec. 31, 2014, there were $61 million of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2015, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:



(Millions of Dollars)	Credit Facility ^(a)		Drawn ^(b)		Available
Xcel Energy Inc.	$	1,000	$	548	$	452
PSCo	700		149		551
NSP-Minnesota	500		100		400
SPS	400		153		247
NSP-Wisconsin	150		80		70
Total	$	2,750	$	1,030	$	1,720


^(a)	These credit facilities expire in October 2019.


^(b)	Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at March 31, 2015 and Dec. 31, 2014.


8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity 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 and international equity 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 Xcel Energy’s evaluation of its redemption rights, 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.

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

Table of Contents

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.

Electric commodity derivatives held by NSP-Minnesota may include transmission congestion instruments purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, SPP and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in the fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Non-Derivative Instruments Fair Value Measurements

The Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $332.2 million and $312.1 million at March 31, 2015 and Dec. 31, 2014, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $58.7 million and $74.1 million at March 31, 2015 and Dec. 31, 2014, respectively.

Table of Contents

The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at March 31, 2015 and Dec. 31, 2014:



	March 31, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	20,836	$	20,836	$	—	$	—	$	20,836
Commingled funds	470,810		—		489,704		—		489,704
International equity funds	123,123		—		120,608		—		120,608
Private equity investments	86,318		—		—		113,619		113,619
Real estate	46,339		—		—		67,774		67,774
Debt securities:
Government securities	24,188		—		23,796		—		23,796
U.S. corporate bonds	64,574		—		60,712		—		60,712
International corporate bonds	16,429		—		16,234		—		16,234
Municipal bonds	201,125		—		206,814		—		206,814
Asset-backed securities	2,828		—		2,847		—		2,847
Mortgage-backed securities	12,292		—		12,787		—		12,787
Equity securities:
Common stock	395,104		601,714		—		—		601,714
Total	$	1,463,966	$	622,550	$	933,502	$	181,393	$	1,737,445


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $81.8 million of equity investments in unconsolidated subsidiaries and $48.2 million of miscellaneous investments.



	Dec. 31, 2014
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	24,184	$	24,184	$	—	$	—	$	24,184
Commingled funds	470,013		—		465,615		—		465,615
International equity funds	80,454		—		78,721		—		78,721
Private equity investments	73,936		—		—		101,237		101,237
Real estate	43,859		—		—		64,249		64,249
Debt securities:
Government securities	30,674		—		28,808		—		28,808
U.S. corporate bonds	81,463		—		77,562		—		77,562
International corporate bonds	16,950		—		16,341		—		16,341
Municipal bonds	242,282		—		249,201		—		249,201
Asset-backed securities	9,131		—		9,250		—		9,250
Mortgage-backed securities	23,225		—		23,895		—		23,895
Equity securities:
Common stock	369,751		564,858		—		—		564,858
Total	$	1,465,922	$	589,042	$	949,393	$	165,486	$	1,703,921


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $83.1 million of equity investments in unconsolidated subsidiaries and $45.6 million of miscellaneous investments.

Table of Contents

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three months ended March 31, 2015 and 2014:



(Thousands of Dollars)	Jan. 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		March 31, 2015
Private equity investments	$	101,237	$	12,382	$	—		$	—	$	113,619
Real estate	64,249		3,861		(1,381		)	1,045		67,774
Total	$	165,486	$	16,243	$	(1,381	)	$	1,045	$	181,393

(Thousands of Dollars)	Jan. 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Asset ^(a)		March 31, 2014
Private equity investments	$	62,696	$	8,769	$	—		$	2,336	$	73,801
Real estate	57,368		3,660		—			1,926		62,954
Total	$	120,064	$	12,429	$	—		$	4,262	$	136,755


^(a)	Gains are deferred as a component of the regulatory assets for nuclear decommissioning.

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at March 31, 2015:



	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years			Total
Government securities	$	—	$	—	$	—	$	23,796		$	23,796
U.S. corporate bonds	473		13,627		49,626		(3,014		)	60,712
International corporate bonds	—		4,494		11,334		406			16,234
Municipal bonds	716		32,054		35,877		138,167			206,814
Asset-backed securities	—		—		2,847		—			2,847
Mortgage-backed securities	—		—		—		12,787			12,787
Debt securities	$	1,189	$	50,175	$	99,684	$	172,142		$	323,190

Derivative Instruments Fair Value Measurements

Xcel Energy 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, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — Xcel Energy 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 March 31, 2015, accumulated other comprehensive losses related to interest rate derivatives included $3.1 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 any unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — Xcel Energy enters 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 energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives.

Table of Contents

At March 31, 2015, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2015 and 2014.

At March 31, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options and FTRs at March 31, 2015 and Dec. 31, 2014:


^(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.

The following tables detail the impact of derivative activity during the three months ended March 31, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:



	Three Months Ended March 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	941	^(a)	$	—			$	—
Vehicle fuel and other commodity	(18		)	—			26		^(b)	—				—
Total	$	(18	)	$	—		$	967		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—			$	3,880	^(c)
Electric commodity	—			(9,471		)	—			(5,123		)	^(d)	—
Natural gas commodity	—			(216		)	—			(8,831		)	^(e)	8,991		^(e)
Total	$	—		$	(9,687	)	$	—		$	(13,954	)		$	12,871

Table of Contents



	Three Months Ended March 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Losses Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)		Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—	$	946		^(a)	$	—	$	—
Vehicle fuel and other commodity	(12		)	—		(28		)	^(b)	—		—
Total	$