NORTHERN STATES POWER CO - FORM 10-Q

NORTHERN STATES POWER CO - FORM 10-Q - August 1, 2014

Attached files

Attached files

NORTHERN STATES POWER CO Reports

file	filename
EXCEL - IDEA: XBRL DOCUMENT - NORTHERN STATES POWER CO	Financial_Report.xls
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO	nspmex3101q22014.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO	nspmex9901q22014.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO	nspmex3102q22014.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO	nspmex3201q22014.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2014



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

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)



Minnesota		41-1967505
(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 ¨	Accelerated filer ¨

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

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

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



Class		Outstanding at Aug. 1, 2014
Common Stock, $0.01 par value		1,000,000 shares

Northern States Power Company (a Minnesota corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS



PART I —	FINANCIAL INFORMATION

Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 4 —	Controls and Procedures	40

PART II —	OTHER INFORMATION

Item 1 —	Legal Proceedings	40
Item 1A —	Risk Factors	40
Item 4 —	Mine Safety Disclosures	40
Item 5 —	Other Information	40
Item 6 —	Exhibits	41

SIGNATURES		42

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

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

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended June 30						Six Months Ended June 30
	2014			2013			2014			2013
Operating revenues
Electric, non-affiliates	$	884,339		$	860,234		$	1,830,874		$	1,701,410
Electric, affiliates	116,518			110,997			238,323			221,135
Natural gas	116,381			107,451			465,913			342,737
Other	7,521			6,163			13,975			12,798
Total operating revenues	1,124,759			1,084,845			2,549,085			2,278,080

Operating expenses
Electric fuel and purchased power	395,130			416,178			853,213			805,079
Cost of natural gas sold and transported	74,427			64,767			337,308			223,537
Cost of sales — other	4,174			3,839			8,301			7,414
Operating and maintenance expenses	308,520			286,422			606,101			559,702
Conservation program expenses	30,291			21,178			66,908			46,057
Depreciation and amortization	101,906			103,735			201,091			212,820
Taxes (other than income taxes)	55,015			46,680			117,175			106,135
Total operating expenses	969,463			942,799			2,190,097			1,960,744

Operating income	155,296			142,046			358,988			317,336

Other (expense) income, net	(471		)	(1,003		)	1,533			1,150
Allowance for funds used during construction — equity	5,995			12,339			11,259			22,601

Interest charges and financing costs
Interest charges — includes other financing costs of $1,619, $1,552 ,$3,212 and $3,038 respectively	49,089			46,477			96,541			91,591
Allowance for funds used during construction — debt	(2,730		)	(5,407		)	(5,185		)	(9,996		)
Total interest charges and financing costs	46,359			41,070			91,356			81,595

Income before income taxes	114,461			112,312			280,424			259,492
Income taxes	39,195			34,611			96,794			79,826
Net income	$	75,266		$	77,701		$	183,630		$	179,666

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended June 30					Six Months Ended June 30
	2014		2013			2014		2013
Net income	$	75,266	$	77,701		$	183,630	$	179,666

Other comprehensive income (loss)

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $4, $17, $8 and $32, respectively	6		21			11		45

Derivative instruments:
Net fair value increase (decrease), net of tax of $7, $(17), $4 and $(8), respectively	10		(24		)	6		(19		)
Reclassification of losses to net income, net of tax of $138, $142, $271 and $277, respectively	200		195			393		388
	210		171			399		369
Marketable securities:
Net fair value increase (decrease), net of tax of $0, $0, $26 and $(22), respectively	—		—			37		(32		)

Other comprehensive income	216		192			447		382
Comprehensive income	$	75,482	$	77,893		$	184,077	$	180,048

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Six Months Ended June 30
	2014			2013
Operating activities
Net income	$	183,630		$	179,666
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	203,803			215,375
Nuclear fuel amortization	60,466			49,485
Deferred income taxes	75,185			86,471
Amortization of investment tax credits	(910		)	(1,339		)
Allowance for equity funds used during construction	(11,259		)	(22,601		)
Net realized and unrealized hedging and derivative transactions	(1,132		)	761
Changes in operating assets and liabilities:
Accounts receivable	(42,406		)	(61,455		)
Accrued unbilled revenues	46,614			6,608
Inventories	39,086			3,551
Other current assets	(7,177		)	44,212
Accounts payable	(88,173		)	(14,054		)
Net regulatory assets and liabilities	67,529			29,939
Other current liabilities	(33,407		)	10,159
Pension and other employee benefit obligations	(47,456		)	(66,292		)
Change in other noncurrent assets	33,355			15,662
Change in other noncurrent liabilities	(21,633		)	(9,698		)
Net cash provided by operating activities	456,115			466,450

Investing activities
Utility capital/construction expenditures	(590,432		)	(763,109		)
Proceeds from insurance recoveries	6,000			50,000
Allowance for equity funds used during construction	11,259			22,601
Purchases of investments in external decommissioning fund	(404,780		)	(890,700		)
Proceeds from the sale of investments in external decommissioning fund	401,488			887,500
Investments in utility money pool arrangement	(236,000		)	(20,000		)
Repayments from utility money pool arrangement	236,000			20,000
Other, net	(1,267		)	(1,198		)
Net cash used in investing activities	(577,732		)	(694,906		)

Financing activities
Repayments of short-term borrowings, net	(104,000		)	(196,000		)
Borrowings under utility money pool arrangement	313,000			526,000
Repayments under utility money pool arrangement	(347,000		)	(506,000		)
Proceeds from issuance of long-term debt	295,534			395,150
Capital contributions from parent	95,000			120,000
Dividends paid to parent	(118,492		)	(117,447		)
Net cash provided by financing activities	134,042			221,703

Net change in cash and cash equivalents	12,425			(6,753		)
Cash and cash equivalents at beginning of period	42,920			28,842
Cash and cash equivalents at end of period	$	55,345		$	22,089

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(87,595	)	$	(77,865	)
Cash (paid) received for income taxes, net	(8,355		)	33,262
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	143,407		$	155,462

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)



	June 30, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	55,345		$	42,920
Accounts receivable, net	325,160			284,532
Accounts receivable from affiliates	21,547			19,769
Accrued unbilled revenues	208,798			255,412
Inventories	240,829			279,915
Regulatory assets	233,241			207,467
Derivative instruments	107,336			66,726
Deferred income taxes	75,762			80,095
Prepayments and other	110,898			118,036
Total current assets	1,378,916			1,354,872

Property, plant and equipment, net	10,846,776			10,589,522

Other assets
Nuclear decommissioning fund and other investments	1,739,314			1,655,356
Regulatory assets	920,596			990,204
Derivative instruments	16,572			36,881
Other	37,367			68,060
Total other assets	2,713,849			2,750,501
Total assets	$	14,939,541		$	14,694,895

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	13		$	2
Short-term debt	27,000			131,000
Borrowings under utility money pool arrangement	—			34,000
Accounts payable	378,470			554,265
Accounts payable to affiliates	63,061			65,941
Regulatory liabilities	159,356			101,795
Taxes accrued	158,256			195,734
Accrued interest	61,325			59,846
Dividends payable to parent	73,749			58,752
Derivative instruments	12,040			13,066
Other	120,213			104,544
Total current liabilities	1,053,483			1,318,945

Deferred credits and other liabilities
Deferred income taxes	2,330,685			2,253,915
Deferred investment tax credits	28,292			29,202
Regulatory liabilities	430,755			430,999
Asset retirement obligations	1,777,271			1,732,763
Derivative instruments	141,330			151,651
Pension and employee benefit obligations	259,807			307,282
Other	103,288			100,614
Total deferred credits and other liabilities	5,071,428			5,006,426

Commitments and contingencies
Capitalization
Long-term debt	4,188,248			3,888,730
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively	10			10
Additional paid in capital	2,961,603			2,866,603
Retained earnings	1,686,051			1,635,910
Accumulated other comprehensive loss	(21,282		)	(21,729		)
Total common stockholder’s equity	4,626,382			4,480,794
Total liabilities and equity	$	14,939,541		$	14,694,895

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

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


1.	Summary of Significant Accounting Policies

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


2.	Accounting Pronouncements

Recently Issued

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


3.	Selected Balance Sheet Data



(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	344,185		$	304,748
Less allowance for bad debts	(19,025		)	(20,216		)
	$	325,160		$	284,532



(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	149,574	$	144,140
Fuel	67,746		81,971
Natural gas	23,509		53,804
	$	240,829	$	279,915

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(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	14,021,511		$	13,530,767
Natural gas plant	1,104,839			1,092,314
Common and other property	506,552			503,168
Construction work in progress	802,571			902,820
Total property, plant and equipment	16,435,473			16,029,069
Less accumulated depreciation	(5,886,077		)	(5,783,658		)
Nuclear fuel	2,200,534			2,186,799
Less accumulated amortization	(1,903,154		)	(1,842,688		)
	$	10,846,776		$	10,589,522


4.	Income Taxes

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

Federal Tax Loss Carryback Claims — In 2012 and 2013, NSP-Minnesota identified certain expenses related to 2009, 2010, 2011 and 2013 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, NSP-Minnesota recognized a tax benefit of approximately $15 million in 2012 and $12 million in 2013.

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2014, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

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



(Millions of Dollars)	June 30, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	5.6	$	8.5
Unrecognized tax benefit — Temporary tax positions	16.3		16.7
Total unrecognized tax benefit	$	21.9	$	25.2

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



(Millions of Dollars)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(12.5	)	$	(12.4	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $4 million.

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


5.	Rate Matters

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

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

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 is 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 reflects an 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 includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, NSP-Minnesota requested a rate increase of $127 million or 4.6 percent in 2014 and an incremental rate increase of $164 million or 5.6 percent in 2015.

NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess depreciation reserve and the use of expected funds from the U.S. Department of Energy (DOE) for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund NSP-Minnesota’s decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello life cycle management (LCM)/extended power uprate (EPU) project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island (PI) EPU project.

In December 2013, the MPUC approved interim rates of $127 million effective Jan. 3, 2014, subject to refund. The MPUC determined that the costs of Sherco Unit 3 would be allowed in interim rates, and that NSP-Minnesota’s request to accelerate the depreciation reserve amortization was a permissible adjustment to its interim rate request.

In June 2014, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) recommended an increase of approximately $61.6 million in 2014 and a step increase of $54.9 million for 2015, based on a recommended ROE of 9.8 percent and an equity ratio of 52.5 percent. The DOC also recommended adoption of a full decoupling pilot for the residential and small commercial and industrial class, based on actual results (not weather-normalized) for three years and made rate design and cost allocation recommendations.

Several other intervenors also filed testimony and included the following recommendations:


•	One or more of these parties made recommendations seeking modifications to rate design, supporting, modifying or opposing decoupling, and proposing inclining block rates and advocating for modification and application of the excess nuclear depreciation reserve.


•	One or more of these parties also made revenue requirement adjustments, including some of the same adjustments recommended by the DOC, such as the exclusion of the Monticello EPU, sales forecast and modifying or eliminating PI EPU amortization.


•	Other key revenue adjustments include:


◦	Amortization of excess depreciation reserve for nuclear plant;


◦	Seeking to exclude two owned wind projects from the step rate increase;


◦	Denial of the Multi-Year Plan step rate increase;


◦	An ROE recommendation of 9 percent;


◦	Modification to the capital structure; and


◦	Exclusion of construction work in progress and allowance for funds used during construction (AFUDC) from rates and adjustments to AFUDC rates and application.

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In July 2014, NSP-Minnesota filed rebuttal testimony and reduced its request to an increase in revenues of approximately $169.5 million or 6.2 percent in 2014 and an additional $95 million or 3.5 percent in 2015. The revision reflects an update to NSP-Minnesota’s 2014 sales forecast and narrowed the number of disputed issues in the case by agreeing to or partially agreeing to an outcome on several smaller issues. NSP-Minnesota continues to support its initial filed position, including cost recovery of the Monticello LCM/EPU project, an ROE of 10.25 percent and property taxes. For the 2015 increase, NSP-Minnesota reduced its request by $3.5 million in order to focus the request on specific capital projects.

The following table summarizes the DOC’s recommendations from NSP-Minnesota’s filed request:



(Millions of Dollars)	DOC Direct Testimony 2014			NSP-Minnesota Rebuttal Testimony 2014
Filed rate request	$	192.7		$	192.7
Monticello EPU cost recovery	(31.3		)	—
Sales forecast	(29.5		)	(15.8		)
ROE	(26.9		)	—
Health care, pension and other benefits	(21.9		)	(0.8		)
Property taxes	(13.5		)	—
PI EPU	(5.8		)	(3.8		)
Other, net	(2.2		)	(2.8		)
Total recommendation 2014	$	61.6		$	169.5



(Millions of Dollars)	DOC Direct Testimony 2015 Step			NSP-Minnesota Rebuttal Testimony 2015 Step
Filed rate request	$	98.5		$	98.5
Depreciation	(17.5		)	—
Property taxes	(14.5		)	(3.3		)
Production tax credits to be included in base rates	(11.1		)	(11.1		)
DOE settlement proceeds	(10.8		)	10.1
Capital changes and disallowances	(5.6		)	—
Nuclear outage amortization	(5.5		)	—
Emission chemicals	(3.0		)	(0.2		)
Excess depreciation reserve adjustment	22.7			—
Other, net	1.7			1.0
Total recommendation 2015 step increase	54.9			95.0
Cumulative total for 2014 and 2015 step increase	$	116.5		$	264.5

NSP-Minnesota’s rebuttal rate request, moderation plan, interim rate adjustments and certain impacts on expenses are detailed in the table below:



(Millions of Dollars)	2014			Percentage Increase	2015			Percentage Increase
Rebuttal pre-moderation deficiency	$	250			$	68
Moderation change compared to prior year:
Depreciation reserve	(81		)		53
DOE settlement proceeds	—				(26		)
Rebuttal rate request	169			6.2%	95			3.5%
Interim rate adjustments	(66		)		66
PI EPU	4				(4		)
Revenue impact ^(a)	107				157
Depreciation expense - decrease/(increase)	81				(46		)
Recognition of DOE settlement proceeds	—				26
Rebuttal pre-tax impact on operating income	$	188			$	137


^(a)	NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request.

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NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with interim rates of approximately $12.5 million as of June 30, 2014.

The next steps in the procedural schedule are expected to be as follows:


•	Surrebuttal Testimony — Aug. 4, 2014;


•	Evidentiary Hearing — Aug. 11-18, 2014;


•	Initial Brief — Sept. 23, 2014;


•	Reply Brief — Oct. 14, 2014; and


•	Administrative Law Judge (ALJ) Report — Dec. 22, 2014.

A final MPUC decision is anticipated in March 2015.

NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. 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). Project expenditures were initially estimated at approximately $320 million, excluding AFUDC, in 2008 in NSP-Minnesota’s EPU certificate of need (CON) and plant life extension filings.

In October 2013, NSP-Minnesota filed a report to further support the change and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken by other utilities and the project remains economically beneficial to customers. NSP-Minnesota has received all necessary licenses from the NRC for the Monticello EPU, and has begun the process to comply with the license requirements for higher power levels, subject to NRC oversight and review.

On July 2, 2014, the DOC filed testimony and recommended a disallowance of recovery of approximately $71.5 million of project costs, including expenditures and associated AFUDC, on a Minnesota jurisdictional basis. This equates to a total NSP System amount of approximately $94 million.

The DOC’s recommendation indicated that although the combined LCM/EPU project is cost effective, NSP-Minnesota should have done a better job of estimating initial project costs of the investments required to achieve 71 megawatts (MW) of additional capacity (i.e., EPU costs) as opposed to investments required to extend the life of the plant. They asserted that approximately 85 percent of the total $665 million in costs were associated with project components required solely to achieve the EPU.

The DOC’s recommendation, NSP-Minnesota’s response and comments of other parties are expected to be considered by an ALJ later this year, who in turn will make a report of recommendations to the MPUC. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s pending Minnesota 2014 Multi-Year electric rate case.

The next steps in the procedural schedule are expected to be as follows:


•	Rebuttal Testimony — Aug. 26, 2014;


•	Surrebuttal Testimony — Sept. 19, 2014;


•	Hearing — Sept. 25 - Sept. 30, 2014;


•	Reply Brief — Nov. 21, 2014; and


•	ALJ Report — Dec. 31, 2014.

A final MPUC decision is anticipated in the first quarter of 2015.

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Electric, Purchased Gas and Resource Adjustment Clauses

NSP-Minnesota - Gas Utility Infrastructure Cost (GUIC) Rider — In August 2014, NSP-Minnesota plans to file a GUIC rider with the MPUC for approval to recover the cost of natural gas infrastructure investments in Minnesota to improve safety and reliability. Costs include funding for pipeline assessment and system upgrades in 2015 and beyond, as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. Sewer separation costs stem from the inspection of sewer lines and the redirection of gas pipes in the event their paths are in conflict. NSP-Minnesota is requesting recovery of approximately $14.9 million from Minnesota gas utility customers beginning Jan.1, 2015, including $4.8 million of deferred sewer separation and integrity management costs. An MPUC decision is anticipated by the end of 2014.

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

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 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 Transmission Cost Recovery (TCR) rider and Infrastructure rider projects to base rates.

The major components of the request are as follows:



(Millions of Dollars)	Request
Nuclear investments and operating costs	$	13.4
Other production, transmission and distribution	5.0
Technology improvements	2.1
Pension and operating and maintenance (O&M) expenses	1.6
Wind generation facilities	1.4
Capital structure	1.1
Incremental increase to base rates	$	24.6

Infrastructure rider to be included in base rates	$	(8.4	)
TCR rider to be included in base rates	(0.6		)
Net request	$	15.6

A procedural schedule is anticipated to be established in the second half of 2014. Final rates are expected to be effective in the first quarter of 2015.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

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

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

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


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, NSP-Minnesota purchases power from independent power producing entities for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,069 MW of capacity under long-term PPAs as of June 30, 2014 and Dec. 31, 2013 with entities that have been determined to be variable interest entities. NSP-Minnesota 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 2028.

Guarantees — Under NSP-Minnesota’s railcar lease agreement, accounted for as an operating lease, NSP-Minnesota guarantees the lessor proceeds from sale of the leased assets at the end of the lease term will at least equal the guaranteed residual value. The guarantee issued by NSP-Minnesota limits their exposure to a maximum amount stated in the guarantee; however, NSP-Minnesota expects sale proceeds to exceed the guaranteed amount. This lease agreement expires in 2019.

The following table presents the guarantee issued and outstanding for NSP-Minnesota:



(Millions of Dollars)	June 30, 2014		Dec. 31, 2013
Guarantees issued and outstanding	$	4.9	$	9.2

Environmental Contingencies

Environmental Requirements

Water and waste

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

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. NSP-Minnesota estimates the most likely cost for compliance is approximately $44 million and anticipates these costs will be fully recoverable in rates.

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

Air

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

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

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

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

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address 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, including Minnesota. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule. The rule would also create an emissions trading program.

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

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions. The CAIR does not currently apply to Minnesota.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous 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), Minnesota identified the NSP-Minnesota facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a 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 selective catalytic reduction (SCRs) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls have been installed and the scrubber upgrades, to be completed by January 2015, are underway. These emission controls are projected to cost approximately $50 million, of which $44.4 million has already been spent. NSP-Minnesota anticipates these costs will be fully recoverable in rates.

After the CSAPR was adopted in 2011, the MPCA supplemented its SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. In June 2012, the EPA approved the SIP for electric generating units and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the 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 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. It is not yet known how the U.S. Supreme Court’s April 2014 decision on the CSAPR, or the EPA’s June 2014 motion requesting the D.C. Circuit lift its stay of the CSAPR, will impact the Eighth Circuit’s proceedings on the SIP. Since the Court’s ruling on CSAPR, the parties to this case have filed motions that continue to hold the case in abeyance while they determine how to proceed. The Eighth Circuit granted these motions and the case is in abeyance until at least Aug. 15, 2014. If this litigation ultimately results in further EPA proceedings concerning the SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

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 U.S. Department of the Interior (DOI) certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from 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.

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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 consent decree recites it will be subject to public comment. The EPA will then evaluate comments and determine whether to enter the consent decree with the District Court. The consent decree establishes a schedule whereby the EPA would issue a proposal on Feb. 27, 2015, determining whether visibility impairment in the national parks is reasonably attributable to Sherco Units 1 and 2. If the EPA determines that it is, the consent decree requires the EPA to make a final RAVI BART determination for these units by Aug. 31, 2015. If the EPA determines that it is not, the EPA would not determine BART for Sherco Units 1 and 2. NSP-Minnesota will contest the proposed consent decree and object to its entry given NSP-Minnesota’s right to intervene in the litigation and thus participate in the negotiation of any purported settlement of the case.

Legal Contingencies

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

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011. In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. In October 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. In April 2013, enXco filed a notice of appeal to the Eighth Circuit. In July 2014, the Eighth Circuit issued a decision that affirmed the U.S. District Court’s dismissal of the lawsuit filed by enXco. It is uncertain at this time whether enXco will challenge this decision. Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter.

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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. NSP-Minnesota has received a total of $181.9 million of settlement proceeds as of June 30, 2014. NSP-Minnesota’s next claim submission, in the amount of $33.6 million, was filed May 15, 2014, for costs incurred in 2013. The DOE has until Sept. 1, 2014 to accept or deny the claim, in whole or in part. 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.


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. 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. Money pool borrowings for NSP-Minnesota were as follows:



(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			34
Average amount outstanding	1			42
Maximum amount outstanding	17			211
Weighted average interest rate, computed on a daily basis	0.21		%	0.14		%
Weighted average interest rate at period end	N/A			0.25

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Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Minnesota was as follows:



(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	500		$	500
Amount outstanding at period end	27			131
Average amount outstanding	108			97
Maximum amount outstanding	280			347
Weighted average interest rate, computed on a daily basis	0.24		%	0.34		%
Weighted average interest rate at period end	0.24			0.25

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2014 and Dec. 31, 2013, there were $23.9 million and $15.9 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

At June 30, 2014, NSP-Minnesota had the following committed credit facility available (in millions):



Credit Facility ^(a)		Drawn ^(b)		Available
$	500.0	$	50.9	$	449.1


^(a)	Credit facility expires in July 2017.


^(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 credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at June 30, 2014 and Dec. 31, 2013.

Long-Term Borrowings

In May 2014, NSP-Minnesota issued $300 million of 4.125 percent first mortgage bonds due May 15, 2044.


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.

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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 NSP-Minnesota’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.

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 include transmission congestion instruments purchased from MISO, PJM Interconnection, LLC (PJM), Electric Reliability Council of Texas, Southwest Power Pool, Inc. (SPP) and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). FTRs purchased from an 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. NSP-Minnesota’s 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 fuel and purchased energy cost recovery mechanisms, 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 NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

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Non-Derivative Instruments Fair Value Measurements

The 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 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 $295.7 million and $240.3 million at June 30, 2014 and Dec. 31, 2013, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $39.3 million and $58.5 million at June 30, 2014 and Dec. 31, 2013, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements, in the nuclear decommissioning fund, at June 30, 2014 and Dec. 31, 2013:



	June 30, 2014
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	26,344	$	26,344	$	—	$	—	$	26,344
Commingled funds	469,692		—		483,482		—		483,482
International equity funds	78,812		—		87,748		—		87,748
Private equity investments	63,096		—		—		81,123		81,123
Real estate	49,421		—		—		65,658		65,658
Debt securities:
Government securities	34,393		—		30,545		—		30,545
U.S. corporate bonds	80,647		—		84,230		—		84,230
International corporate bonds	15,919		—		16,432		—		16,432
Municipal bonds	225,508		—		228,506		—		228,506
Asset-backed securities	9,218		—		9,334		—		9,334
Mortgage-backed securities	24,097		—		24,250		—		24,250
Equity securities:
Common stock	376,214		572,065		—		—		572,065
Total	$	1,453,361	$	598,409	$	964,527	$	146,781	$	1,709,717


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $29.6 million of miscellaneous investments.

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	Dec. 31, 2013
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	33,281	$	33,281	$	—	$	—	$	33,281
Commingled funds	457,986		—		452,227		—		452,227
International equity funds	78,812		—		81,671		—		81,671
Private equity investments	52,143		—		—		62,696		62,696
Real estate	45,564		—		—		57,368		57,368
Debt securities:
Government securities	34,304		—		27,628		—		27,628
U.S. corporate bonds	80,275		—		83,538		—		83,538
International corporate bonds	15,025		—		15,358		—		15,358
Municipal bonds	241,112		—		232,016		—		232,016
Equity securities:
Common stock	406,695		581,243		—		—		581,243
Total	$	1,445,197	$	614,524	$	892,438	$	120,064	$	1,627,026


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $28.3 million of miscellaneous investments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2014 and 2013:



(Thousands of Dollars)	April 1, 2014		Purchases		Settlements		Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3		June 30, 2014
Private equity investments	$	73,801	$	2,184	$	—	$	5,138	$	—	$	81,123
Real estate	62,954		197		—		2,507		—		65,658
Total	$	136,755	$	2,381	$	—	$	7,645	$	—	$	146,781



(Thousands of Dollars)	April 1, 2013		Purchases		Settlements			Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3		June 30, 2013
Private equity investments	$	34,506	$	7,298	$	—		$	3,786	$	—	$	45,590
Real estate	40,406		2,032		(4,723		)	425		—		38,140
Total	$	74,912	$	9,330	$	(4,723	)	$	4,211	$	—	$	83,730



(Thousands of Dollars)	Jan. 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3			June 30, 2014
Private equity investments	$	62,696	$	10,953	$	—		$	7,474	$	—		$	81,123
Real estate	57,368		3,856		—			4,434		—			65,658
Total	$	120,064	$	14,809	$	—		$	11,908	$	—		$	146,781

(Thousands of Dollars)	Jan. 1, 2013		Purchases		Settlements			Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3 ^(a)			June 30, 2013
Private equity investments	$	33,250	$	8,554	$	—		$	3,786	$	—		$	45,590
Real estate	39,074		6,818		(9,022		)	1,270		—			38,140
Asset-backed securities	2,067		—		—			—		(2,067		)	—
Mortgage-backed securities	30,209		—		—			—		(30,209		)	—
Total	$	104,600	$	15,372	$	(9,022	)	$	5,056	$	(32,276	)	$	83,730


^(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.

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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2014:



	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	$	—	$	—	$	—	$	30,545	$	30,545
U.S. corporate bonds	307		15,358		66,131		2,434		84,230
International corporate bonds	—		3,854		12,578		—		16,432
Municipal bonds	2,608		26,902		36,195		162,801		228,506
Asset-backed securities	—		—		3,540		5,794		9,334
Mortgage-backed securities	—		—		—		24,250		24,250
Debt securities	$	2,915	$	46,114	$	118,444	$	225,824	$	393,297

Derivative Instruments Fair Value Measurements

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

At June 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.8 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 — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’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 — NSP-Minnesota 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 and vehicle fuel.

At June 30, 2014, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. NSP-Minnesota 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. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2014 and 2013.

At June 30, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota 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 revenue, net of amounts credited to customers under margin-sharing mechanisms.

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The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2014 and Dec. 31, 2013:


^(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 and six months ended June 30, 2014 and 2013 on accumulated other comprehensive loss, regulatory assets and liabilities and income:



	Three Months Ended June 30, 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 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	$	—	$	—		$	346		^(a)	$	—			$	—
Vehicle fuel and other commodity	17		—			(8		)	^(b)	—				—
Total	$	17	$	—		$	338			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	5,175	^(c)
Electric commodity	—		(16,347		)	—				(6,461		)	^(d)	—
Natural gas commodity	—		(493		)	—				—				—
Other commodity	—		—			—				—				643		^(c)
Total	$	—	$	(16,840	)	$	—			$	(6,461	)		$	5,818



	Six Months Ended June 30, 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	$	—	$	—		$	688		^(a)	$	—			$	—
Vehicle fuel and other commodity	10		—			(24		)	^(b)	—				—
Total	$	10	$	—		$	664			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	2,922		^(c)
Electric commodity	—		(11,448		)	—				(24,387		)	^(d)	—
Natural gas commodity	—		7,408			—				(9,306		)	^(e)	(580		)	^(e)
Other commodity	—		—			—				—				643			^(c)
Total	$	—	$	(4,040	)	$	—			$	(33,693	)		$	2,985

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	Three Months Ended June 30, 2013
	Pre-Tax Fair Value Gains (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	$	—		$	—	$	346		^(a)	$	—			$	—
Vehicle fuel and other commodity	(41		)	—		(9		)	^(b)	—				—
Total	$	(41	)	$	—	$	337			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—			$	(498	)	^(c)
Electric commodity	—			53,974		—				(13,764		)	^(d)	—
Total	$	—		$	53,974	$	—			$	(13,764	)		$	(498	)



	Six Months Ended June 30, 2013
	Pre-Tax Fair Value Gains (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	$	—		$	—	$	688		^(a)	$	—			$	—
Vehicle fuel and other commodity	(27		)	—		(23		)	^(b)	—				—
Total	$	(27	)	$	—	$	665			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—			$	2,278	^(c)
Electric commodity	—			60,393		—				(28,993		)	^(d)	—
Natural gas commodity	—			2		—				—				—
Total	$	—		$	60,395	$	—			$	(28,993	)		$	2,278


^(a)	Amounts are recorded to interest charges.


^(b)	Amounts are recorded to O&M expenses.


^(c)	Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.


^(d)	Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.


^(e)	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

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

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

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

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2014, nine of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $26.5 million or 27 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining one significant counterparty, comprising $2.1 million or 2 percent of this credit exposure, was not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (NPNS) contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. At June 30, 2014 and Dec. 31, 2013, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2014 and Dec. 31, 2013.

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Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2014:



	June 30, 2014
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	33	$	—	$	33	$	—		$	33
Other derivative instruments:
Commodity trading	—		21,311		7,586		28,897		(9,225		)	19,672
Electric commodity	—		—		68,047		68,047		(2,709		)	65,338
Natural gas commodity	—		1,593		—		1,593		—			1,593
Other commodity	—		—		643		643		—			643
Total current derivative assets	$	—	$	22,937	$	76,276	$	99,213	$	(11,934	)	87,279
PPAs ^(a)												20,057
Current derivative instruments												$	107,336
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	19	$	—	$	19	$	—		$	19
Other derivative instruments:
Commodity trading	—		17,792		180		17,972		(3,399		)	14,573
Total noncurrent derivative assets	$	—	$	17,811	$	180	$	17,991	$	(3,399	)	14,592
PPAs ^(a)												1,980
Noncurrent derivative instruments												$	16,572
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	12,076	$	2,295	$	14,371	$	(14,371	)	$	—
Electric commodity	—		—		2,709		2,709		(2,709		)	—
Total current derivative liabilities	$	—	$	12,076	$	5,004	$	17,080	$	(17,080	)	—
PPAs ^(a)												12,040
Current derivative instruments												$	12,040
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	5,562	$	—	$	5,562	$	(5,474	)	$	88
Total noncurrent derivative liabilities	$	—	$	5,562	$	—	$	5,562	$	(5,474	)	88
PPAs ^(a)												141,242
Noncurrent derivative instruments												$	141,330

^(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2014. At June 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $7.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:



	Dec. 31, 2013
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	48	$	—	$	48	$	—		$	48
Other derivative instruments:
Commodity trading	—		17,854		1,167		19,021		(6,718		)	12,303
Electric commodity	—		—		30,692		30,692		(1,723		)	28,969
Natural gas commodity	—		1,986		—		1,986		—			1,986
Total current derivative assets	$	—	$	19,888	$	31,859	$	51,747	$	(8,441	)	43,306
PPAs ^(a)												23,420
Current derivative instruments												$	66,726
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	16	$	—	$	16	$	(16	)	$	—
Other derivative instruments:
Commodity trading	—		32,074		3,395		35,469		(9,071		)	26,398
Total noncurrent derivative assets	$	—	$	32,090	$	3,395	$	35,485	$	(9,087	)	26,398
PPAs ^(a)												10,483
Noncurrent derivative instruments												$	36,881
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	8,108	$	1,804	$	9,912	$	(9,912	)	$	—
Electric commodity	—		—		1,723		1,723		(1,723		)	—
Total current derivative liabilities	$	—	$	8,108	$	3,527	$	11,635	$	(11,635	)	—
PPAs ^(a)												13,066
Current derivative instruments												$	13,066
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	14,382	$	—	$	14,382	$	(10,137	)	$	4,245
Total noncurrent derivative liabilities	$	—	$	14,382	$	—	$	14,382	$	(10,137	)	4,245
PPAs ^(a)												147,406
Noncurrent derivative instruments												$	151,651

^(a)

^(b)

NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30
(Thousands of Dollars)	2014			2013
Balance at April 1	$	18,426		$	7,642
Purchases	81,689			51,386
Settlements	(20,056		)	(8,503		)
Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)	6,438			(217		)
Losses recognized as regulatory assets and liabilities	(15,045		)	(3,090		)
Balance at June 30	$	71,452		$	47,218

	Six Months Ended June 30
(Thousands of Dollars)	2014			2013
Balance at Jan. 1	$	31,727		$	16,649
Purchases	81,689			51,386
Settlements	(72,764		)	(20,952		)
Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)	7,437			(279		)
Gains recognized as regulatory assets and liabilities	23,363			414
Balance at June 30	$	71,452		$	47,218


^(a)	These amounts relate to commodity derivatives held at the end of the period.

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2014 and 2013.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:



	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,188,261	$	4,654,697	$	3,888,732	$	4,099,745

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


9.	Other (Expense) Income, Net

Other (expense) income, net consisted of the following:



	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	1,045		$	254		$	3,754		$	3,652
Other nonoperating income (expense)	38			(156		)	406			121
Insurance policy expense	(1,554		)	(1,101		)	(2,627		)	(2,623		)
Other (expense) income, net	$	(471	)	$	(1,003	)	$	1,533		$	1,150

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10.	Segment Information

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

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


•	NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.


•	NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.


•	Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

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

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues ^(a)(b)	$	1,000,857	$	116,381	$	7,521	$	—		$	1,124,759
Intersegment revenues	252		220		—		(472		)	—
Total revenues	$	1,001,109	$	116,601	$	7,521	$	(472	)	$	1,124,759
Net income	$	70,811	$	41	$	4,414	$	—		$	75,266



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues ^(a)(b)	$	971,231	$	107,451	$	6,163		$	—		$	1,084,845
Intersegment revenues	164		254		—			(418		)	—
Total revenues	$	971,395	$	107,705	$	6,163		$	(418	)	$	1,084,845
Net income (loss)	$	78,195	$	2,595	$	(3,089	)	$	—		$	77,701


^(a)	Operating revenues include $117 million and $111 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013, respectively.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2014 and 2013.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues ^(a)(b)	$	2,069,197	$	465,913	$	13,975	$	—		$	2,549,085
Intersegment revenues	416		496		—		(912		)	—
Total revenues	$	2,069,613	$	466,409	$	13,975	$	(912	)	$	2,549,085
Net income	$	149,066	$	27,100	$	7,464	$	—		$	183,630

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues ^(a)(b)	$	1,922,545	$	342,737	$	12,798	$	—		$	2,278,080
Intersegment revenues	299		399		—		(698		)	—
Total revenues	$	1,922,844	$	343,136	$	12,798	$	(698	)	$	2,278,080
Net income	$	148,193	$	23,733	$	7,740	$	—		$	179,666


^(a)	Operating revenues include $238 million and $221 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.


^(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2014 and 2013, respectively.


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost



	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,425		$	8,291		$	46		$	30
Interest cost	11,827			10,933			1,249			1,225
Expected return on plan assets	(15,730		)	(15,788		)	(76		)	(104		)
Amortization of transition obligation	—			—			—			8
Amortization of prior service cost (credit)	234			514			(759		)	(759		)
Amortization of net loss	11,196			13,247			854			1,318
Net periodic benefit cost	14,952			17,197			1,314			1,718
Costs not recognized due to the effects of regulation	(7,312		)	(6,772		)	—			—
Net benefit cost recognized for financial reporting	$	7,640		$	10,425		$	1,314		$	1,718



	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	14,850		$	16,583		$	93		$	60
Interest cost	23,654			21,867			2,497			2,450
Expected return on plan assets	(31,460		)	(31,576		)	(151		)	(208		)
Amortization of transition obligation	—			—			—			16
Amortization of prior service cost (credit)	468			1,028			(1,518		)	(1,518		)
Amortization of net loss	22,392			26,494			1,708			2,636
Net periodic benefit cost	29,904			34,396			2,629			3,436
Costs not recognized due to the effects of regulation	(15,071		)	(13,544		)	—			—
Net benefit cost recognized for financial reporting	$	14,833		$	20,852		$	2,629		$	3,436

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $52.1 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2014.

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12.	Other Comprehensive Income

Changes in accumulated other comprehensive gain (loss), net of tax, for the three and six months ended June 30, 2014 and 2013 were as follows:



	Three Months Ended June 30, 2014
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) gain at April 1	$	(20,420	)	$	110	$	(1,188	)	$	(21,498	)
Other comprehensive gain before reclassifications	10			—		—			10
Losses reclassified from net accumulated other comprehensive loss	200			—		6			206
Net current period other comprehensive income	210			—		6			216
Accumulated other comprehensive (loss) gain at June 30	$	(20,210	)	$	110	$	(1,182	)	$	(21,282	)



	Three Months Ended June 30, 2013
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(21,195	)	$	(131	)	$	(1,683	)	$	(23,009	)
Other comprehensive loss before reclassifications	(24		)	—			—			(24		)
Losses reclassified from net accumulated other comprehensive loss	195			—			21			216
Net current period other comprehensive income	171			—			21			192
Accumulated other comprehensive loss at June 30	$	(21,024	)	$	(131	)	$	(1,662	)	$	(22,817	)



	Six Months Ended June 30, 2014
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) gain at Jan. 1	$	(20,609	)	$	73	$	(1,193	)	$	(21,729	)
Other comprehensive gain before reclassifications	6			37		—			43
Losses reclassified from net accumulated other comprehensive loss	393			—		11			404
Net current period other comprehensive income	399			37		11			447
Accumulated other comprehensive (loss) gain at June 30	$	(20,210	)	$	110	$	(1,182	)	$	(21,282	)



	Six Months Ended June 30, 2013
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(21,393	)	$	(99	)	$	(1,707	)	$	(23,199	)
Other comprehensive loss before reclassifications	(19		)	(32		)	—			(51		)
Losses reclassified from net accumulated other comprehensive loss	388			—			45			433
Net current period other comprehensive income (loss)	369			(32		)	45			382
Accumulated other comprehensive loss at June 30	$	(21,024	)	$	(131	)	$	(1,662	)	$	(22,817	)

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Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Gain (Loss)
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	346		^(a)	$	346		^(a)
Vehicle fuel derivatives	(8		)	^(b)	(9		)	^(b)
Total, pre-tax	338				337
Tax benefit	(138		)		(142		)
Total, net of tax	200				195
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	58			^(c)	85			^(c)
Prior service credit	(48		)	^(c)	(47		)	^(c)
Transition obligation	—			^(c)	—			^(c)
Total, pre-tax	10				38
Tax benefit	(4		)		(17		)
Total, net of tax	6				21
Total amounts reclassified, net of tax	$	206			$	216



	Amounts Reclassified from Accumulated Other Comprehensive Gain (Loss)
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	688		^(a)	$	688		^(a)
Vehicle fuel derivatives	(24		)	^(b)	(23		)	^(b)
Total, pre-tax	664				665
Tax benefit	(271		)		(277		)
Total, net of tax	393				388
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	116			^(c)	170			^(c)
Prior service credit	(97		)	^(c)	(94		)	^(c)
Transition obligation	—			^(c)	1			^(c)
Total, pre-tax	19				77
Tax benefit	(8		)		(32		)
Total, net of tax	11				45
Total amounts reclassified, net of tax	$	404			$	433


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.


^(c)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

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

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

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Financial Review

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

Forward-Looking Statements

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

Results of Operations

NSP-Minnesota’s net income was approximately $183.6 million for the six months ended June 30, 2014, compared with approximately $179.7 million for the same period in 2013. Electric rate increases in Minnesota (interim, subject to refund) and North Dakota, lower depreciation expense, weather-normalized sales growth (which is adjusted against a 30-year average of actual historical weather conditions) and the favorable year-over-year impact of weather were partially offset by higher O&M expenses, lower AFUDC and higher property taxes.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:



	Six Months Ended June 30
(Millions of Dollars)	2014			2013
Electric revenues	$	2,069		$	1,923
Electric fuel and purchased power	(853		)	(805		)
Electric margin	$	1,216		$	1,118

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

Electric Revenues



(Millions of Dollars)	2014 vs. 2013
Retail rate increases^(a)	$	29
Trading revenue	26
Conservation program revenue (offset by expenses)	20
Non-fuel riders	17
Interchange revenues from NSP-Wisconsin	17
Transmission revenue	16
Estimated impact of weather	10
Fuel and purchased power cost recovery	7
Retail sales growth (excluding weather impact)	7
Other, net	(3		)
Total increase in electric revenues	$	146

Electric Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increases^(a)	$	29
Conservation program revenue (offset by expenses)	20
Non-fuel riders	17
Interchange revenues from NSP-Wisconsin	14
Estimated impact of weather	10
Retail sales growth (excluding weather impact)	7
Transmission revenue, net of costs	6
Other, net	(5		)
Total increase in electric margin	$	98


^(a)	Retail rates implemented in 2014 include interim rates in Minnesota, subject to refund, and final rates for North Dakota. See Note 5 to the consolidated financial statements for further discussion of rates and regulation.

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details natural gas revenues and margin:



	Six Months Ended June 30
(Millions of Dollars)	2014			2013
Natural gas revenues	$	466		$	343
Cost of natural gas sold and transported	(337		)	(224		)
Natural gas margin	$	129		$	119

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

Natural Gas Revenues



(Millions of Dollars)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	110
Estimated impact of weather	6
Conservation program revenue (offset by expenses) and incentives	2
Other, net	5
Total increase in natural gas revenues	$	123

Natural Gas Margin



(Millions of Dollars)	2014 vs. 2013
Estimated impact of weather	$	6
Conservation program revenue (offset by expenses) and incentives	2
Other, net	2
Total increase in natural gas margin	$	10

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $46.4 million, or 8.3 percent, for the six months ended June 30, 2014. The increase in O&M expense is partially due to the timing of a prior year nuclear outage (i.e., amortization of the 2013 Monticello outage began in July 2013), as summarized in the table below for the six months ended June 30:



(Millions of Dollars)	2014 vs. 2013
Nuclear plant operations and amortization	$	27
Electric and gas distribution expenses	4
Interchange agreement billing with NSP-Wisconsin	4
Transmission costs	3
Generation costs	3
Employee benefits	(2		)
Other, net	7
Total increase in O&M expenses	$	46


•	Nuclear plant operations and amortization cost increases were primarily related to the amortization of the 2013 Monticello outage costs, as well as initiatives designed to improve the operational efficiencies of the plants.

Conservation Program Expenses — Conservation program expenses increased $20.9 million, or 45.3 percent, for the six months ended June 30, 2014. This increase was primarily attributable to higher electric recovery rates. Conservation costs are recovered from customers and expensed on a kilowatt hour (KWh) basis. As such, increased sales due to cold winter temperatures or hot summer temperatures will increase revenues and expenses.

Depreciation and Amortization — Depreciation and amortization expense decreased $11.7 million, or 5.5 percent, year-to-date. The decrease was primarily attributed to additional accelerated amortization of the excess depreciation reserve associated with certain Minnesota assets, partially offset by normal system expansion. See further discussion within Note 5 to the consolidated financial statements.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $11.0 million, or 10.4 percent, for the six months ended June 30, 2014. The increase was due to higher property taxes primarily in Minnesota.

AFUDC, Equity and Debt — AFUDC decreased $16.2 million year-to-date. The decrease was due to the reduction caused by the portion of the Monticello LCM/EPU placed in service in July 2013, partially offset by construction related to the expansion of transmission facilities.

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Interest Charges — Interest charges increased $5.0 million, or 5.4 percent, for the six months ended June 30, 2014. The increase was primarily due to higher long-term debt levels in the current period, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $17.0 million for the six months ended June 30, 2014. The increase in income tax expense was primarily due to higher pretax earnings in 2014, decreased permanent plant-related adjustments in 2014, recognition of research and experimentation credits in 2013 due to the passage of the American Taxpayer Relief Act and a tax benefit for a carryback claim related to 2013. These were partially offset by the successful resolution of a 2010-2011 IRS audit issue in 2014 and increased wind production tax credits in 2014. The ETR was 34.5 percent for the first six months of 2014, compared with 30.8 percent for the first six months of 2013 due to these adjustments.

Public Utility Regulation

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

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

In early 2013, NSP-Minnesota also issued a request for proposal (RFP) for wind generation and subsequently sought commission approval of the following four wind projects:


•	A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota;


•	A 150 MW ownership project for the Border Winds wind farm in North Dakota;


•	A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and


•	A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.

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

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

CapX2020 — In 2009, the MPUC granted CONs to construct one 230 kilovolt (KV) electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project. The estimated cost of the five major CapX2020 transmission projects listed below is $2.1 billion. NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.2 billion of the total investment. As of June 30, 2014, Xcel Energy has invested $821 million of its $1.2 billion share of the five CapX2020 transmission projects.

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV transmission line

In May 2012, the MPUC issued a route permit for the Minnesota portion of the project and the Public Service Commission of Wisconsin approved a certificate of public convenience and necessity (CPCN) for the Wisconsin portion of the project. Federal approval of the project was granted in January 2013. All avenues of appeal for the grant of project permits have now been exhausted. In July 2013, the FERC denied a complaint filed by two citizen groups in March 2013 against the project. Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.

Monticello, Minn. to Fargo, N.D. 345 KV transmission line

In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the Monticello, Minn. to Fargo, N.D. project was placed in service. The MPUC issued a route permit for the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. section in June 2011. Construction started on the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. segment in January 2012. In April 2014, the St. Cloud, Minn. to Alexandria, Minn. portion of the project was placed in service. The NDPSC granted a CPCN in January 2011 and a certificate of corridor compatibility and route permit for the portion of the line in North Dakota in September 2012. In January 2013, construction started on the project in North Dakota. The final phase of the project, Alexandria, Minn. to Fargo, N.D. is expected to go into service in 2015.

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Brookings County, S.D. to Hampton, Minn. 345 KV transmission line

The MPUC route permit approvals for the Minnesota segments were obtained in 2010 and 2011. In June 2011, the SDPUC approved a facility permit for the South Dakota segment. In December 2011, MISO granted the final approval of the project as a multi-value project (MVP). Construction started on the project in Minnesota in May 2012. The project is expected to go fully into service in 2015, although segments will be placed in service as they are completed.

Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line

The Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.

Big Stone South to Brookings County, S.D. 345 KV transmission line

In December 2011, MISO granted final approval of the project as a MVP. In March 2014, the SDPUC approved a permit for construction of the project’s southern portion. Construction is anticipated to begin in late 2015, with completion in 2017.

Minnesota Solar — Minnesota legislation requires 1.5 percent of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized less than 20 kilowatts. There are two new solar programs approved: a community solar garden program that will provide bill credits to participating subscribers and a production incentive program for solar energy systems equal to or less than 20 kilowatts with authorized payments of $5.0 million over five years. The legislation also provides for an alternative tariff based on a distributed solar value or Value of Solar (VOS) methodology.

In March 2014, the DOC’s proposed VOS methodology was approved by the MPUC however, NSP-Minnesota disagrees with including the VOS in the community solar garden program. In June 2014, NSP-Minnesota submitted reply comments and a recalculation of the VOS rate to recognize lower costs and incorporate DOC assumptions. If the MPUC requires the VOS rate, and NSP-Minnesota’s VOS rate calculation is approved, production from solar gardens would earn 9.4 cents per KWh, adjusted annually for inflation. If the VOS rate is not required by the MPUC, it may approve a retail rate based credit ranging from 9.5 to 15 cents per KWh. The actual bill credit amount is dependent on tariff service the customer receives as well as their willingness to transfer the renewable energy credit (REC) to NSP-Minnesota. An MPUC decision on community solar gardens, including the bill credit rate, is expected in the third quarter of 2014.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. See Note 14 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 for further discussion regarding the nuclear generating plants.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota. Decisions by the NRC can significantly impact the operations of the nuclear generating plants. The event at the nuclear generating plant in Fukushima, Japan in 2011 has resulted in additional regulation regarding plant readiness to safely manage severe events, which is expected to require additional capital expenditures and operating expenses.

In March 2012, the NRC issued three orders which included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant. The NRC also requested additional information including requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant. Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016.

In June 2013, the NRC issued a revised order with regard to reliable hardened containment vents. The revised order added severe accident conditions under which the existing hardened vent which comes off of the wet portion of the containment needs to operate and requires a second hardened vent off of the dry portion of the containment. The revised order requires that any necessary changes to the existing vent are to be completed by the second quarter of the 2017 refueling outage at the Monticello plant and a new vent to be added by the second quarter of the 2019 refueling outage. Portions of the work that fall under the requests for additional information are expected to be completed by 2018.

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NSP-Minnesota expects that complying with these external event requirements will cost approximately $80 to $100 million at the Monticello and PI plants. The majority of these costs are expected to be capital in nature and are included in NSP-Minnesota’s capital expenditure forecasts. NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

The NRC continues to review its requirements for mitigating the risks of external events on nuclear plants. In April 2014, the NRC issued a draft of proposed regulatory guidance for risk mitigation of tornado missiles (projectiles impacting the plant). This draft guidance is subject to public comments, further NRC review and possibly public meetings prior to finalization. NSP-Minnesota expects the costs associated with compliance with new NRC regulatory guidance for missile protection to be capital in nature and recoverable from customers. However, at this time NSP-Minnesota is still evaluating the proposed new requirements and has not yet estimated their financial impact.

Summary of Recent Federal Regulatory Developments

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

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

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

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

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

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

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

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

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

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

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Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

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

Item 1A — RISK FACTORS

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

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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Item 6 — EXHIBITS

* Indicates incorporation by reference



3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 000-31387)).
4.01*	Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125 percent First Mortgage Bonds, Series due May 15, 2044. (Exhibit 4.01 to NSP-Minnesota’s Form 8-K dated May 13, 2014 (file no. 001-31387)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

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



		Northern States Power Company (a Minnesota corporation)

Aug. 1, 2014	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller

		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

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

June 30, 2014

Dec. 31, 2013

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel